UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

(Mark One)

 

☒  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended December 31, 2014

 

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)

 

State of incorporation: Delaware		I.R.S. Employer Identification No. 26-0818050
1700 Broadway - Suite 1170 - Denver, Colorado		80290
(Address of Principal Executive Offices)		(Zip Code)
Registrant's telephone number, including area code: (720) 407-7030
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Title of Each Class		Name of Each Exchange on which Registered
Common Stock, Par Value $0.01 Per Share		None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☐

 

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 the definition 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 ☐ (Do not check if a smaller reporting company)

Smaller reporting company ☒

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒

 

The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 30, 2014, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $42.1 million (based on the closing price of such stock).

 

There were 106,875,447 shares of the registrant's common stock, par value $0.01 per share, outstanding as of March 5, 2015.

 

 

 

CARBON NATURAL GAS COMPANY

TABLE OF CONTENTS

 

 

 

		Page No.
PART I
Item 1.	Business	4
Item 1A.	Risk Factors	18
Item 1B.	Unresolved Staff Comments	29
Item 2.	Properties	29
Item 3.	Legal Proceedings	29
Item 4.	Mine Safety Disclosures	29
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	30
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	31
Item 8.	Financial Statements and Supplementary Data	43
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	68
Item 9A.	Controls and Procedures	68
Item 9B.	Other Information	69
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	69
Item 11.	Executive Compensation	73
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	78
Item 13.	Certain Relationships and Related Transactions, and Director Independence	80
Item 14.	Principal Accountant Fees and Services	81
PART IV
Item 15.	Exhibits, Financial Statement Schedules	82
	Signatures	85

 

 

PART I

 

Item 1.    Business.

 

General

 

Throughout this Annual Report on Form 10-K, we use the terms "Carbon," "Company," "we," "our," and "us" to refer to Carbon Natural Gas Company and its subsidiaries. In the following discussion, we make statements that may be deemed "forward-looking" statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). See "Forward-Looking Statements," below, for more details. We also use a number of terms used in the oil and gas industry. See "Glossary of Oil and Gas Terms" for the definition of certain terms.

 

Carbon Natural Gas Company is a Delaware corporation, originally formed in Indiana in 1959, which owns and operates oil and natural gas and oil interests in the Appalachian and Illinois Basins of the United States. It produces and sells oil, natural gas, natural gas condensate and natural gas liquids. Carbon’s acreage is held and its exploration and production activities are conducted indirectly through majority-owned subsidiaries.

 

●

Nytis Exploration (USA) Inc. (“Nytis USA”) was organized as a Delaware corporation in 2004. Pursuant to the Merger, Nytis USA is owned 100% by Carbon.

 

●

In 2005 Nytis USA identified oil and natural gas interests (owned by Addington Exploration, LLC (“Addington”)) located primarily in Illinois, Indiana, Kentucky, Ohio, Tennessee and West Virginia. To acquire the Addington assets, Nytis USA formed (along with a different unaffiliated person) Nytis Exploration Company LLC (“Nytis LLC”). Nytis LLC is owned 98.1% by Nytis USA.

 

●

On January 31, 2011, Nytis USA entered into an Agreement and Plan of Merger (the “Merger Agreement”) with St. Lawrence Seaway Corporation (“SLSC”), which was closed on February 14, 2011. At that date, SLSC acquired all of the issued and outstanding shares of Nytis USA from the Nytis USA stockholders, and thereby became the indirect owner of all of Nytis USA’s equity interests in Nytis LLC. In exchange for the issuance by SLSC to the Nytis USA stockholders of 47,000,003 restricted shares of SLSC common stock (which then constituted 98.9% of SLSC’s issued and outstanding common stock), Nytis USA became a wholly-owned subsidiary of SLSC, and Nytis LLC became a majority-owned indirect subsidiary of SLSC (the “Merger”). The transactions contemplated by the Merger Agreement were intended to be a “tax-free” reorganization under Sections 351 and/or 368 of the Internal Revenue Code of 1986.

 

●

Now, substantially all the oil and natural gas interests are owned by Nytis LLC, which continues to acquire and develop properties. As of December 31, 2014, Nytis LLC owned interests in approximately 907 gross (595 net) productive oil and natural gas wells and approximately 291,000 (239,000 net) undeveloped acres in the Appalachian and Illinois Basins.

 

In connection with the closing of the Merger, the officers and directors of Nytis USA became the officers and directors of SLSC.

 

Prior to the Merger closing, SLSC was a “shell company” (as defined in Rule 12b-2 under the Securities Exchange Act of 1934 (the “Exchange Act”)), with no operations and nominal cash assets. As a result of the Merger, SLSC exited shell company status as of February 17, 2011, when it filed a Form 8-K with complete “Form 10 Information” as required by Item 2.01(f) of Form 8-K. On May 2, 2011, SLSC’s name was changed to Carbon Natural Gas Company.

 

Carbon is a holding company which conducts substantially all its oil and natural gas operations through Nytis LLC. Nytis LLC also holds an interest in 46 consolidated partnerships and records the non-controlling owners’ interest in net assets and income.

 

Strategy

 

Our strategy is to create shareholder value through consistent growth in production and reserves by drilling on existing properties and the acquisition of complementary properties. We emphasize the development of the Company’s existing leasehold which consists primarily of low risk, repeatable resource plays. We invest significantly in technical staff, and geological and engineering technology to enhance the value of our properties.

 

Principal strategy components:

 

●

Concentrate on resources in core operating areas. Our current focus on the Appalachian and Illinois Basins allows the Company to capitalize on its regional expertise to optimize drilling and completion techniques and production and reserve growth. Numerous objective reservoirs permit us to allocate capital among opportunities based on risked well economics, with a view to balancing the portfolio to achieve consistent and profitable growth in production and reserves.

 

 

		Some of our proved reserves and resources are classified as unconventional, including fractured shale formations, tight gas sands, and coalbed methane. Our technical team has significant experience in drilling vertical, horizontal and directional wells, as well as fracture stimulation of unconventional formations. We utilize geological, drilling and completion technologies to enhance the predictability and repeatability of finding and recovering hydrocarbons in these unconventional plays.
	●	Focus on oil development. The Company has, since 2011, focused on the drilling of its oil prospects and the Company expects to continue to allocate capital to oil drilling activities. The Company maintains an inventory of natural gas prospects which, in an appropriate natural gas price environment, may provide the opportunity for significant drilling activity, cash flow and reserve additions.

 

●

Increased production and reserves. Production increased from an average of approximately 7,900 Mcfe per day for the year ended December 31, 2013 to an average of approximately 8,100 Mcfe per day for the year ended December 31, 2014. Estimated proved reserves increased from 41.6 Bcfe at December 31, 2013 to 42.1 Bcfe at December 31, 2014 (including 3.3 Bcfe of estimated proved reserves attributable to minority interest of consolidated partnerships for each year).

 

●

Proven executive management team with track record of value creation.   Our management and technical personnel have extensive experience operating in the Appalachian and Illinois Basins, and have successfully developed exploration and production companies in the past.

 

●

Low-risk development drilling in established resource plays, and flexibility in deployment of exploration and infrastructure capital. The Company’s acreage positions provide multiple resource play opportunities. At an appropriate level of oil and natural gas prices, the Company has a multi-year drilling inventory of potential horizontal drilling locations on existing acreage. Carbon has drilled or participated in over 166 vertical or horizontal wells from January 2005 through December 31, 2014. Our leasehold position has been delineated largely through drilling done by us, as well as with other industry players. Our leasehold position is largely comprised of leases held-by-production or long-term leases which allows the Company to select the optimum time to drill.

 

●

Low cost operation. Our geographic and operating focus and the shallow nature of our drilling activities and producing wells results in relatively low finding and development and lease operating costs.

 

●

Maintain financial flexibility and conservative financial position. We typically use cash flow from operations and our bank credit facility with Bank of Oklahoma to fund drilling and acquisition activities.

 

●

Control over operating decisions and capital program.  At December 31, 2014, we had an average working interest of approximately 66% in our productive wells and operated approximately 91% of our production. The high percentage of operated wells allows us to control operating costs, and to better manage the timing of development activities, and the marketing of production.

 

●

Manage commodity price exposure through an active hedging program. We maintain a hedging program designed to mitigate volatility in commodity prices and regional basis differentials. As of December 31, 2014, we have outstanding natural gas hedges of 750,000 MMbtu for 2015 at an average price of $4.05 per MMbtu and 40,000 MMBtu for 2016 at an average price of $4.20 per MMBtu and oil hedges of 10,000 barrels for 2015 at an average price of $94.66.

 

●

Manage midstream assets and secure firm takeaway capacity. We own natural gas gathering and compression facilities in the Appalachian and Illinois Basins. We believe that owning gathering and compression facilities allows us to decrease dependence on third parties, and to better manage the timing of our development and to receive higher netback pricing from the markets in which we sell our production. We have secured long-term firm takeaway capacity on major pipelines to accommodate the transportation and marketing of certain of our existing and expected production.

 

 

Core Operational Areas

 

Our oil and gas properties are located primarily in Illinois, Indiana, Kentucky, Ohio, Tennessee, and West Virginia. The map below shows locations of the Company’s oil and natural gas properties as of December 31, 2014.

 

 

Appalachian Basin

 

As of December 31, 2014, Nytis LLC owns working interests in 849 gross wells (566 net) and royalty wells located in Kentucky, Ohio, Tennessee and West Virginia, and has leasehold positions in approximately 33,500 net developed acres and approximately 174,300 net undeveloped acres.  As of December 31, 2014, net sales were approximately 7,700 Mcfe per day. Objective formations are the Berea Sandstone, Chattanooga Shale, Devonian Shale, Lower Huron Shale and other zones which produce oil and natural gas. 

 

Illinois Basin

 

As of December 31, 2014, Nytis LLC owns working interests in 58 gross (29 net) coalbed methane wells in the Illinois Basin and has a leasehold position in approximately 1,700 net developed acres and approximately 64,800 net undeveloped acres.  As of December 31, 2014, net natural gas sales were approximately 450 Mcf per day.

 

Acquisition and Divestiture Activities

 

We pursue acquisitions that meet our criteria for investment returns and are consistent with our low-risk development focus. Acquisitions in and around our existing core areas enable us to leverage our cost control abilities, technical expertise, and existing land and infrastructure positions. Our acquisition program has focused on acquisitions of properties that have development drilling opportunities and undeveloped acreage. The following is a summary of our significant acquisitions and divestitures during the last two years. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 3 to the Consolidated Financial Statements and “Recent Developments” for more information on our acquisitions and dispositions.

 

Participation Agreement

 

On February 25, 2014, Nytis LLC entered into a participation agreement with Liberty Energy LLC (“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 will pay a disproportionate percentage of the costs associated with drilling and completing 20 wells on the covered leases.

 

Following the drilling of these 20 wells, Nytis LLC and Liberty will pay their respective costs on a basis proportionate to their working interests.

 

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

 

 

Acquisitions

 

During the year ended December 31, 2014, for nominal cash and assumption of nominal partner liabilities, the Company acquired partnership interests from other partners.

 

Divestitures

 

On December 15, 2014, Nytis LLC together with Liberty, (the “Sellers”) completed a preliminary closing in accordance with a Purchase and Sale Agreement (the “PSA”) entered into on October 15, 2014, as amended, 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 (the “Leases”).

 

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 closing of this transaction, Nytis LLC received approximately $12.4 million in cash with the proceeds from the sale recorded as a reduction of the Company’s investment in its proved and unevaluated oil and natural gas properties.

 

At the preliminary closing, the buyer provided to Sellers a description of title defects and estimated that the extent of title defects was less than the twenty percent (20%) threshold provided in the PSA that would have permitted either buyer or Sellers to terminate the transaction.

 

A final closing is scheduled for mid-April 2015 at which time the Sellers’ curative work and substitute acreage will be agreed to and may result in a downward revision of the purchase price.

 

Reserves

 

The Company holds an interest in 64 partnerships, 46 of which are consolidated. The following table summarizes our estimated quantities of proved reserves and the pre-tax PV-10 as of December 31, 2014 and 2013 after consolidating these partnerships in which the Company has a controlling interest.

 

Pre-tax PV-10, which is not a financial measure accepted under GAAP, is shown because it is a widely used industry standard.

 

Estimated Consolidated Proved Reserves

Including Non-Controlling Interests of Consolidated Partnerships

 

		December 31,
		2014				2013
Proved developed reserves:
Natural gas (MMcf)			35,935				35,317
Oil and liquids (MBbl)			770				748
Total proved developed reserves (MMcfe)			40,555				39,805
Proved undeveloped reserves:
Natural gas (MMcf)			1,013				1,367
Oil and liquids (MBbl)			83				74
Total proved undeveloped reserves (MMcfe)			1,511				1,811
Total proved reserves (MMcfe)			42,066				41,616
Percent developed			96.4	%			95.6	%
PV-10 (thousands)		$	67,016			$	56,442
Average natural gas price used (per Mcf)		$	4.64			$	3.84
Average oil and liquids price used (per Bbl)		$	92.10			$	94.08

 

The estimated quantities of proved reserves for the non-controlling interests of the consolidated partnerships as of December 31, 2014 are approximately 3.3 Bcfe which is approximately 8% of total consolidated proved reserves.

 

 

The following table summarizes our estimated quantities of proved reserves and the pre-tax PV10, excluding the non-controlling interests of the consolidated partnerships, as of December 31, 2014 and 2013.

 

Estimated Proved Reserves Excluding Non-Controlling Interests of Consolidating Partnerships

 

		December 31,
		2014				2013
Proved developed reserves:
Natural gas (MMcf)			32,644				32,007
Oil and liquids (MBbl)			770				748
Total proved developed reserves (MMcfe)			37,264				36,495
Proved undeveloped reserves:
Natural gas (MMcf)			1,013				1,367
Oil and liquids (MBbl)			83				74
Total proved undeveloped reserves (MMcfe)			1,511				1,811
Total proved reserves (MMcfe)			38,775				38,306
Percent developed			96.1	%			95.3	%
PV-10 (thousands)		$	63,155			$	53,326
Average natural gas price used (per Mcf)		$	4.64			$	3.84
Average oil and liquids price used (per Bbl)		$	92.10			$	94.08

 

Preparation of Reserves Estimates

 

Our proved oil and natural gas reserves estimates as of December 31, 2014 and 2013 were based on the average fiscal-year prices for oil and natural gas (calculated as the unweighted arithmetic average of the first-day-of-the month price for each month within the 12-month period ended December 31, 2014 and 2013 respectively). Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Proved undeveloped reserves on undrilled acreage are limited to those locations on development spacing areas that are offsetting economic producers that are reasonably certain of economic production when drilled. Proved undeveloped reserves for other undrilled development spacing areas are claimed only where it can be demonstrated with reasonable certainty that there is continuity of economic production from the existing productive formation. Proved undeveloped reserves are included when they are scheduled to be drilled within five years.

 

SEC rules dictate the types of technologies that a company may use to establish reserve estimates including the extraction of non-traditional resources, such as natural gas extracted from shales as well as bitumen extracted from oil sands. See Note 2 to the Consolidated Financial Statements for additional information regarding our estimated proved reserves.

 

Uncertainties are inherent in estimating quantities of proved reserves, including many factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and its interpretation. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing, and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices or development and production expenses, may require revision of such estimates. Accordingly, quantities of oil and natural gas ultimately recovered will vary from reserve estimates. See “Risk Factors,” for a description of some of the risks and uncertainties associated with our business and reserves.

 

 

Reserve estimates are based on production performance, data acquired remotely or in wells, and are guided by petrophysical, geologic, geophysical, and reservoir engineering models. Estimates of our proved reserves were based on deterministic methods. In the case of mature developed reserves, reserve estimates are determined by decline curve analysis and in the case of immature developed and undeveloped reserves, by analogy, using proximate or otherwise appropriate examples. The technologies and economic data used in estimating our proved reserves include empirical evidence through drilling results and well performance, well logs and test data, geologic maps and available downhole and production data. Further, the internal review process of our wells and related reserve estimates includes but is not limited to the following:

 

	●	A comparison is made and documented of actual data from our accounting system to the data utilized in the reserve database. Current production, revenue and expense information obtained from the Company’s accounting records are subject to external quarterly reviews, annual audits and their own set of internal controls over financial reporting. This ensures that production, revenues and expenses are appropriately included in the reserve database.
	●	A comparison is made and documented of land and lease records to ownership interest data in the reserve database. This ensures that the costs and revenues utilized in the reserves estimation match actual ownership interests.
	●	A comparison is made of property acquisitions, disposals, retirements or transfers to the property records maintained in the reserve database to verify that all are accounted for accurately.
	●	Natural gas pricing for the first flow day of every month is collected from Platts Gas Daily.  Oil pricing for the first flow day of every month is provided by the U.S. Energy Information Administration.  At the reporting date, 12-month average prices are determined. A similar collection process occurs with pricing deductions and a 12-month average is calculated at year end.

 

For the years ended December 31, 2014 and 2013, Carbon’s independent engineering firm, Cawley, Gillespie & Associates, Inc. (“CGA”) reviewed field performance and future development plans with Carbon’s technical personnel. Following these reviews, Carbon’s internal reserve database and supporting data was furnished to CGA in order for them to prepare their independent reserve estimates and final report. Access to the database housing reserve information is restricted to select individuals from our engineering department. CGA’s independent reserve estimates and final report is for the Company’s interest in the respective oil and gas properties and represents 100% of the total proved hydrocarbon reserves owned by the Company, or 92% of the consolidated proved hydrocarbon reserves presented in the Company’s Consolidated Financial Statements as CGA’s report does not include the hydrocarbon reserves owned by the non-controlling interests of the consolidated partnerships. The Company calculated the estimated reserves and related PV-10 of the non-controlling interests of the consolidated partnerships’ oil and gas properties by multiplying CG&A’s independent reserve estimates for such properties by the respective non-controlling interests in those properties.

 

CGA is a Texas Registered Engineering Firm. Our primary contact at CGA is J. Zane Meekins, Executive Vice President. Mr. Meekins is a State of Texas Licensed Professional Engineer. See Exhibit 99.1 of the Annual Report on Form 10-K for the Report of CGA.

 

Our Vice President of Engineering, Richard Finucane, is responsible for overseeing the preparation of the reserve estimates with consultations from our internal technical staff. Mr. Finucane oversees engineering, production, property evaluation, acquisitions and divestitures activities for the Company. Mr. Finucane has worked as an oil and natural gas engineer since 1978 and holds a B.S. in Civil Engineering from the University of Tennessee (highest honors) and is admitted as an expert in oil and natural gas matters in civil and regulatory proceedings in Virginia, West Virginia and Kentucky.

 

Drilling Activities

 

The following table summarizes the number of wells drilled for the years ended December 31, 2014, 2013 and 2012. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells.

 

		Year Ended December 31,
		2014								2013								2012
		Gross				Net				Gross				Net				Gross				Net
Development wells:
Productive (1)			17.0				10.5				25.0				15.0				8.0				6.8
Non-productive (2)			-				-				-				-				-				-
Total development wells			17.0				10.5				25.0				15.0				8.0				6.8
Exploratory wells:
Productive (1)			-				-				-				-				-				-
Non-productive (2)			-				-				-				-
Total exploratory wells			-				-				-				-				-				-

 

(1)	A well classified as productive does not always provide economic levels of activity.
(2)	A non-productive well is a well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well; also known as a dry well (or dry hole).

 

 

Oil and Natural Gas Wells and Acreage

 

Productive Wells

 

Productive wells consist of producing wells and wells capable of production, including shut-in wells. A well bore with multiple completions is counted as only one well. The following table summarizes our productive wells as of December 31, 2014.

 

		December 31, 2014
		Gross				Net
Gas			805				512
Oil			102				83
Total			907				595

 

Acreage

 

The following table summarizes gross and net developed and undeveloped acreage by state as of December 31, 2014. Acreage related to royalty, overriding royalty, and other similar interests is excluded from this summary, as well as acreage related to any options held by us to acquire additional leasehold interests.

 

December 31, 2014
		Developed								Undeveloped								Total
		Acres								Acres								Acres
		Gross				Net				Gross				Net				Gross				Net
Indiana			-				-				43,364				43,364				43,364				43,364
Illinois			3,490				1,745				37,879				21,439				41,369				23,184
Kentucky			28,652				25,605				95,769				61,237				124,421				86,842
Ohio			337				337				6,703				6,703				7,040				7,040
Tennessee			100				25				93,605				93,580				93,705				93,605
West Virginia			9,058				7,554				14,104				12,095				23,162				19,649
Total			41,637				35,266				291,424				238,418				333,061				273,684

 

 

Undeveloped Acreage Expirations

 

The following table sets forth gross and net undeveloped acres by state as of December 31, 2014, which are scheduled to expire from the date of the table through 2017 unless production is established within the spacing unit covering the acreage prior to the expiration date or the Company extends the terms of a lease by paying delay rentals to the lessor.

 

December 31, 2014
		2015								2016								2017
		Gross				Net				Gross				Net				Gross				Net
Indiana			-				-				-				-				-				-
Illinois			-				-				15,753				7,877				7,451				3,725
Kentucky			4,335				2,504				1,537				922				548				329
Ohio			-				-				-				-				-				-
Tennessee			-				-				-				-				-				-
West Virginia			-				-				-				-				591				591
Total			4,335				2,504				17,290				8,799				8,590				4,645

 

Production, Average Sales Prices and Production Costs

 

The following table reflects production, average sales price, and production cost information for the years ended December 31, 2014 and 2013.

 

		Year Ended December 31,
		2014				2013
Production data:
Natural gas (MMcf)			2,138				2,252
Oil and condensate (Bbl)			133,532				106,853
Combined (MMcfe)			2,942				2,894
Gas and oil production revenue (in thousands)		$	22,543			$	18,681
Commodity hedge gain/(loss) (in thousands)		$	1,246			$	(459	)
Prices:
Average sales price before effects of hedging;
Natural gas (per Mcf)		$	4.83			$	3.76
Oil and condensate (per Bbl)		$	91.35			$	95.49
Average sale price after effects of hedging:
Natural gas (per Mcf)		$	5.17			$	3.69
Oil and condensate (per Bbl)		$	95.22			$	92.80
Average costs per Mcfe:
Lease operating costs		$	1.13			$	0.91
Transportation costs		$	0.61			$	0.56
Production and property taxes		$	0.56			$	0.43

 

 

The Company

 

Marketing and Delivery Commitments

 

Our oil and natural gas production is generally sold on a month-to-month basis in the spot market, priced in reference to published indices. We believe that the loss of one or more of our purchasers would not have a material adverse effect on our ability to sell our production, because any individual purchaser could be readily replaced by another purchaser, absent a broad market disruption.

 

At December 31, 2014, the Company has a fixed price contract requiring physical deliveries for approximately 530 Bbl/month at an average sales price of $96.75 per Bbl from January 2015 through August 2015.

 

The Company has entered into long-term firm transportation contracts to ensure the transport of certain of its gas production to purchasers. Capacity levels and related demand charges for the remaining term of these contracts at December 31, 2014 are summarized in the table below:

 

Period		Dekatherms per day		Demand Charges
Jan 2015 - May 2015		5,950		$0.20 - $0.67
Jun 2015 - Oct 2015		4,800		$0.20 - $0.67
Nov 2015 - Dec 2017		3,300		$0.22 - $0.67
Jan 2018 - May 2036		1,000		$0.22

 

Competition

 

We encounter competition in all aspects of our business, including acquisition of properties and oil and natural gas leases, marketing oil and natural gas, obtaining services and labor, and securing drilling rigs and other equipment and materials necessary for drilling and completing wells. Our ability to increase reserves in the future will depend on our ability to generate successful prospects on our existing properties, execute on major development drilling programs, and acquire additional leases and prospects for future development and exploration. A large number of the companies we compete with have substantially larger staffs and greater financial and operational resources than we do. Because of the nature of our oil and natural gas assets and management’s experience in exploiting our reserves and acquiring properties, management believes that we effectively compete in our markets. See— Risk Factor “Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.”

 

Regulation

 

Our operations are subject to various U.S. federal, state, and local laws and regulations. These laws and regulations may be changed in response to economic or political conditions. Matters subject to current governmental regulation and/or pending legislative or regulatory changes include the discharge or other release into the environment of wastes and other substances in connection with drilling and production activities (including fracture stimulation operations), bonds or other financial responsibility requirements to cover drilling risks and well plugging and abandonment, reclamation or restoration costs, reports concerning our operations, the spacing of wells, unitization and pooling of properties, taxation, and the use of derivative hedging instruments. Failure to comply with the laws and regulations in effect may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions that could delay, limit, or prohibit certain of our operations. In the past, regulatory agencies have imposed price controls and limitations on production. In order to conserve supplies of oil and gas, oil and gas conservation commissions and other agencies may restrict the rates of flow of wells below actual production capacity, generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. Further, a significant spill from one of our facilities could have a material adverse effect on our results of operations, competitive position, or financial condition. The laws in the U.S., including state laws, regulate, among other things, the production, handling, storage, transportation, and disposal of oil and natural gas, by-products from each, and other substances and materials produced or used in connection with our operations. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations.

 

In August 2005, Congress enacted the Energy Policy Act of 2005 (“EPAct 2005”). Among other matters, EPAct 2005 amends the Natural Gas Act (“NGA”) to make it unlawful for any entity, including otherwise non-jurisdictional producers such as Carbon, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the Federal Energy Regulatory Commission (“FERC”), in contravention of rules prescribed by the FERC. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction. It therefore reflects a significant expansion of the FERC’s enforcement authority. We do not anticipate we will be affected any differently than other producers of natural gas in respect of EPAct 2005.

 

 

In December 2007, the FERC issued rules requiring that any market participant, including a producer such as Carbon, that engages in physical sales for resale or purchases for resale of natural gas that equal or exceed 2.2 million MMBtus during a calendar year must annually report such sales or purchases to the FERC, beginning on May 1, 2009. These rules are intended to increase the transparency of the wholesale natural gas markets and to assist the FERC in monitoring such markets and in detecting market manipulation. On September 18, 2008 the FERC issued its order on rehearing, which largely approved the existing rules, except the FERC exempted from the reporting requirement certain types of purchases and sales, including purchases and sales of unprocessed natural gas and bundled sales of natural gas made pursuant to state regulated retail tariffs. Also, the FERC clarified that other end use purchases and sales are not exempt from the reporting requirements. The monitoring and reporting required by the new rules will likely increase our administrative costs. Carbon does not anticipate it will be affected any differently than other producers of natural gas.

 

Additional proposals and proceedings that might affect the oil and natural gas industry are regularly considered by Congress, the states, the FERC, and the courts. For instance, legislation has been introduced in the U.S. Congress to amend the federal Safe Drinking Water Act to subject hydraulic fracturing operations—an important process used in the completion of our oil and natural gas wells—to regulation under the Safe Drinking Water Act. If adopted, this legislation could establish an additional level of regulation, and impose additional cost, on our operations. We cannot predict when or whether any such proposal, or any additional new legislative or regulatory proposal, may become effective. No material portion of our business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of the federal government.

 

Environmental

 

As an operator of oil and natural gas properties in the U.S., we are subject to federal, state and local laws and regulations relating to environmental protection as well as controlling the manner in which various substances, including wastes generated in connection with exploration, production, and transportation operations, are released into the environment. Compliance with these laws and regulations can affect the location or size of wells and facilities, prohibit or limit the extent to which exploration and development may be allowed, and require proper closure of wells and restoration of properties when production ceases. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, or criminal penalties, imposition of remedial obligations, incurrence of capital or increased operating costs to comply with governmental standards, and even injunctions that limit or prohibit exploration and production activities or that constrain the disposal of substances generated by oil field operations.

 

We currently operate or lease, and have in the past operated or leased, a number of properties that have been subject to the exploration and production of oil and natural gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties operated or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon may be subject to laws and regulations imposing joint and several liability and strict liability without regard to fault or the legality of the original conduct that could require us to remove previously disposed wastes or remediate property contamination, or to perform well or pit closure or other actions of a remedial nature to prevent future contamination.

 

Oil and natural gas deposits exist in shale and other formations. It is customary in our industry to recover oil and natural gas from these formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, underground where water, sand and other additives are pumped under high pressure into a shale formation.

 

Essentially all of our reserves are subject to or have been subjected to hydraulic fracturing. The reservoir rock in these areas, in general, has insufficient permeability to flow enough oil or natural gas to be economically viable without stimulation. The controlling regulatory agencies for well construction have standards that are designed specifically in anticipation of hydraulic fracturing. The stimulation process cost varies according to well location and reservoir. It generally ranges from 10% of the well cost to 30%. To date, no incidents, citations or suits have resulted from our hydraulic fracturing operations.

 

We contract with established service companies to conduct our hydraulic fracturing. The personnel of these service companies are trained to handle potentially hazardous materials and possess emergency protocols and equipment to deal with potential spills and carry Material Safety Data Sheets for all chemicals.

 

In the well completion and production process, an accidental release could result in possible environmental damage. All wells have manifolds with escape lines to containment areas. High pressure valves for flow control are on the wellhead. Valves and piping are designed for higher pressures than are typically encountered. Piping is tested prior to any procedure and regular safety inspections and incident drill records are kept on those tests.

 

 

All fracturing is designed with the minimal water requirements necessary since there is a cost of accumulating, storing and disposing of the water recovered from fracturing. Water is drawn from nearby streams that are tributaries to the Ohio River and flow 365 days per year. Water recovered from the fracturing is injected into EPA or state approved water injection wells.

 

Despite all of these safety procedures, there are many risks involved in hydraulic fracturing that could result in liability to the Company.

 

In 2009, the U.S. House of Representatives passed a bill to control and reduce the emission of domestic greenhouse gases through the grant of emission allowances which would gradually be decreased over time. Although similar bills were considered in the U.S. Senate, such legislation lacked support in Congress. Despite the lack of federal legislation, nearly half of the states, either individually or through multi-state initiatives, have begun implementing legal measures to reduce greenhouse gas emissions. Also, the U.S. Supreme Court held in Massachusetts et al. v. EPA (2007) that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act, which could result in future regulation of greenhouse gas emissions from stationary and non-stationary sources, even if Congress does not adopt new legislation specifically addressing such emissions. In December 2009, the U.S. Environmental Protection Agency (“EPA”) published its findings that emissions of greenhouse gases present an endangerment to public health and the environment because such emissions, according to the EPA, are contributing to warming of the earth’s atmosphere and other climate changes. These findings allow the EPA to implement regulations that would restrict greenhouse gas emissions under existing provisions of the Clean Air Act. Accordingly, the EPA has adopted regulations that require a reduction of greenhouse gas emissions from motor vehicles and has proposed additional regulations to further restrict such emissions.

 

The EPA has also finalized regulations that require certain U.S. facilities, including certain petroleum and natural gas facilities, to report their greenhouse gas emissions beginning on January 1, 2011. The adoption and implementation of these regulations impacts our business, and any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have an adverse effect on demand for the oil and natural gas that we produce.

 

We believe that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards. While we believe that we are in substantial compliance with applicable environmental laws and regulations in effect at the present time and that continued compliance with existing requirements will not have a material adverse impact on us, we cannot give any assurance that we will not be adversely affected in the future. We have established internal guidelines to be followed in order to comply with environmental laws and regulations in the U.S. Although we maintain pollution insurance against the costs of cleanup operations, public liability, and physical damage, there is no assurance that such insurance will be adequate to cover all such costs or that such insurance will continue to be available in the future.

 

Employees

 

As of December 31, 2014, our workforce (including those employed by our subsidiary Nytis LLC) consisted of approximately 30 employees all of which are full-time employees. None of the members of our workforce are represented by a union or covered by a collective bargaining agreement. We believe we have a good relationship with the members of our workforce.

 

Geographical Data

 

Carbon operates in one geographical area, the United States. See Note 1 to the Consolidated Financial Statements.

 

Offices

 

Our executive offices are located at 1700 Broadway, Suite 1170, Denver, Colorado 80290. We maintain an office in Lexington, Kentucky in which we conduct our oil and gas operations.

 

Title to Properties

 

Title to our oil and gas properties is subject to royalty, overriding royalty, carried, net profits, working, and similar interests customary in the oil and gas industry. Under the terms of our bank credit facility, we have granted the lender a lien on a substantial majority of our properties. In addition, our properties may also be subject to liens incident to operating agreements, as well as other customary encumbrances, easements, and restrictions, and for current taxes not yet due. Our general practice is to conduct title examinations on material property acquisitions. Prior to the commencement of drilling operations, a title examination and, if necessary, curative work is performed. The methods of title examination that we have adopted are reasonable in the opinion of management and are designed to ensure that production from our properties, if obtained, will be salable by us.

 

 

Glossary of Oil and Gas Terms

 

Many of the following terms are used throughout this Annual Report on Form 10-K. The definitions of proved developed reserves, proved reserves, and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a) of Regulation S-X adopted by the Securities and Exchange Commission (the “SEC”). The entire definitions of those terms can be viewed on the SEC’s website at http://www.sec.gov.

 

Bbl		means one stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or liquid hydrocarbons.
Bcf		means one billion cubic feet of natural gas.
Bcfe		means one billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate, or natural gas liquids.
Bbtu		means one billion British Thermal Units.
Btu		means a British Thermal Unit, or the amount of heat necessary to raise the temperature of one pound of water one degree Fahrenheit.
CBM		means coalbed methane.
Condensate		means liquid hydrocarbons associated with the production of a primarily natural gas reserve.
Dekatherm		means one million British Thermal Units.
Developed acreage		means the number of acres which are allocated or held by producing wells or wells capable of production.
Development well		means a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Equivalent volumes		means equivalent volumes are computed with oil and natural gas liquid quantities converted to Mcf on an energy equivalent ratio of one barrel to six Mcf.
Exploitation		means ordinarily considered to be a form of development within a known reservoir.
Exploratory well		means a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well or a service well.
Farmout		is an assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location or the undertaking of other work obligations.
Field		means an area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Full cost pool		means the full cost pool consisting of all costs associated with property acquisition, exploration, and development activities for a company using the full cost method of accounting. Additionally, any internal costs that can be directly identified with acquisition, exploration, and development activities are included. Any costs related to production, general and administrative expense, or similar activities are not included.
Gross acres or  gross wells		means the total acres or wells, as the case may be, in which a working interest is owned.
Henry Hub		means the natural gas pipeline located in Erath, Louisiana that serves as the official delivery location for futures contracts on the NYMEX.
Lease operating expenses		means the expenses of lifting oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, and other expenses incidental to production, but not including lease acquisition or drilling or completion expenses.

 

 

Liquids		describes oil, condensate, and natural gas liquids.
MBbls		means one thousand barrels of crude oil or other liquid hydrocarbons.
Mcf		means one thousand cubic feet of natural gas.
Mcfe		means one thousand cubic feet equivalent determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate, or natural gas liquids.
MMBtu		means one million British Thermal Units, a common energy measurement.
MMcf		means one million cubic feet of natural gas.
MMcfe		means one million cubic feet equivalent determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate, or natural gas liquids.
NGL		means natural gas liquids.
Net acres or  net wells		is the sum of the fractional working interest owned in gross acres or gross wells  expressed in whole numbers and fractions of whole numbers.
Non-productive well		means a well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
NYMEX		means New York Mercantile Exchange.
Productive wells		means producing wells and wells that are capable of production, and wells that are shut-in.
Proved Developed Reserves		means estimated proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved Reserves		means quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices that are the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Proved Undeveloped Reserves		means estimated proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recovery to occur.
PV-10		means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect at the determination date, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.  PV-10 is not a financial measure accepted under GAAP.
Reservoir		means a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Royalty		means an interest in an oil or natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

 

 

Standardized measure of present value of estimated future net revenues		means an estimate of the present value of the estimated future net revenues from proved oil or  natural gas reserves at a date indicated after deducting estimated production and ad valorem taxes,  future capital costs, operating expenses and income taxes computed by applying year end statutory tax rates, with consideration of future tax rates already legislated. The estimated future net revenues are discounted at an annual rate of 10%, in accordance with the SEC’s practice, to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future net revenues are made using oil and natural gas prices and operating costs at the estimation date and held constant for the life of the reserves.
Tcfe		means one trillion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate, or natural gas liquids.
Undeveloped acreage		means acreage on which wells have not been drilled or completed to a point that  would permit the production of economic quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.
Working interest		means an operating interest which gives the owner the right to drill, produce, and conduct operating activities on the property, and to receive a share of production.

 

Available Information

 

You may read, without charge, and copy, at prescribed rates, all or any portion of the registration statement or any reports, statements or other information in the files at the public reference room at the SEC’s principal office at 100 F Street NE, Washington, D.C., 20549. You may request copies of these documents, for a copying fee, by writing to the SEC. You may call the SEC at 1-800-SEC-0330 for further information on the operation of its public reference room. Our filings, including this Annual Report on Form 10-K, will also be available to you on the Internet website maintained by the SEC at http://www.sec.gov or on our website at http://www.carbonnaturalgas.com.

 

We are subject to the information and reporting requirements of the Securities Exchange Act and will file annual, quarterly and current reports, proxy statements and other information with the SEC. You can request copies of these documents, for a copying fee, by writing to the SEC. These reports, proxy statements and other information will also be available on the Internet websites of the SEC and the Company referred to above. We intend to furnish our stockholders with annual reports containing financial statements audited by our independent auditors.

 

Forward-Looking Statements

 

The information in this Annual Report on Form 10-K includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 (the “1933 Act”) and Section 21E of the Exchange Act of 1934 (the “1934 Act”). Forward-looking statements are statements other than statements of historical or present facts, that address activities, events, outcomes, and other matters that Carbon 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 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. See "Competition" and "Regulation" above, as well as Part I, Item 1A—"Risk Factors," and Part II, Item 7—"Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources" for a description of various, but by no means all, factors that could materially affect our ability to achieve the anticipated results described in the 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 Annual Report on Form 10-K and attributable to Carbon 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 1A.    Risk Factors.

 

We are subject to certain risks and hazards due to the nature of the business activities we conduct, including the risks discussed below. Any of these risks could materially and adversely affect our business, financial condition, cash flows, and results of operations, and are not the only risks we face. We may experience additional risks and uncertainties not currently known to us; or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows, and results of operations.

 

Oil and natural gas prices are volatile. A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

 

Our financial condition, operating results, and future rate of growth depend upon the prices that we receive for our oil and natural gas. Oil prices have fallen significantly since reaching an average monthly high for the Company of $103.73 per barrel in June 2014, dropping to an average monthly low for the Company of $60.43 per barrel in December 2014. Oil prices have continued to decline during the first quarter of 2015, with the price of West Texas Intermediate crude oil falling below $43.00 a barrel in March 2015. In addition average natural gas prices received by the Company in December 2014 were approximately 10% lower compared to the high realized in mid-2014. Prices also affect our cash flow available for capital expenditures and our ability to access funds under our bank credit facility and through the capital markets. The amount available for borrowing under our bank credit facility is subject to a borrowing base, which is determined by our lender taking into account our estimated proved developed reserves and is subject to periodic redeterminations based on pricing models determined by the lender at such time. Declines in oil and natural gas prices have in the past adversely impacted the value of our estimated proved developed reserves and, in turn, the market values used by our lenders to determine our borrowing base. Future commodity price declines may have similar adverse effects on our reserves and borrowing base. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Bank Credit Facilities,” for more details. Further, because we have elected to use the full cost accounting method, each quarter we must perform a “ceiling test” that is impacted by declining prices. Significant price declines could cause us to take one or more ceiling test write-downs, which would be reflected as non-cash charges against current earnings. See Risk Factor below entitled “Lower oil and natural gas prices and other factors have resulted in, and in the future may result in, ceiling test write-downs and other impairments of our asset carrying values.”

 

 

Historically, the markets for oil and natural gas have been volatile and are likely to remain so in the future. In July 2008, oil spot prices reached historical highs and natural gas spot prices reached near historical highs. Prices have declined significantly since that time and may continue to fluctuate widely in the future. The prices we receive for our oil and natural gas depend upon factors beyond our control, including among others:

  

	●	worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;
	●	the price and quantity of imports of foreign oil and natural gas, including liquefied natural gas;
	●	political conditions in or affecting other oil and natural gas producing countries;
	●	the level of oil and natural gas exploration and production;
	●	the level of global oil and natural gas inventories;
	●	prevailing prices on local oil and natural gas price indexes in the areas in which we operate;
	●	localized and global supply and demand fundamentals and transportation availability;
	●	weather conditions;
	●	technological advances affecting energy supply and consumption;
	●	the price and availability of alternative energy; and
	●	domestic, local and foreign governmental regulation and taxes.

 

These factors make it difficult to predict future commodity price movements with any certainty. We sell the majority of our oil and natural gas production at current prices rather than through fixed-price contracts. However, we do enter into derivative instruments to reduce our exposure to fluctuations in oil and natural gas prices. See Risk Factor below entitled “Future use of hedging arrangements could result in financial losses or reduce income.” At December 31, 2014, 88% of our estimated proved reserves were natural gas, and, as a result, our financial results will be more sensitive to fluctuations in natural gas prices.

 

We have indebtedness and may incur more debt in the future. Our leverage may materially affect our operations and financial condition.

 

We (through Nytis LLC) have a bank credit facility with the Bank of Oklahoma, the outstanding balance of which was approximately $2.1 million at December 31, 2014. We may incur more debt in the future. This indebtedness may have several important effects on our business and operations; among other things, it may:

  

	●	require us to use a significant portion of our cash flow to pay principal and interest on the debt, which will reduce the amount available to fund working capital, capital expenditures, and other general corporate purposes;
	●	limit our access to the capital markets;
	●	increase our borrowing costs, and impact the terms, conditions, and restrictions contained in our debt agreements, including the addition of more restrictive covenants;
	●	limit our flexibility in planning for and reacting to changes in our business as covenants and restrictions contained in our existing and possible future debt arrangements may require that we meet certain financial tests and place restrictions on the incurrence of additional indebtedness;
	●	place us at a disadvantage compared to similar companies in our industry that have less debt; and
	●	make us more vulnerable to economic downturns and adverse developments in our business.

 

Our bank credit facility contains various restrictive covenants. A failure on our part to comply with financial and other restrictive covenants contained in our bank credit facility could result in a default under these agreements. Any default under our bank credit facility could adversely affect our business and our financial condition and results of operations, and would impact our ability to obtain financing in the future. In addition, the borrowing base included in our bank credit facility is subject to periodic redetermination by our lender. A lowering of our borrowing base could require us to repay indebtedness in excess of the redetermined (lower) borrowing base. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Bank Credit Facility.”

 

A higher level of debt will increase the risk that we may default on our financial obligations. Our ability to meet our debt obligations and other expenses will depend on our future performance. Our future performance will be primarily affected by oil and natural gas prices, financial, business, domestic and global economic conditions, governmental regulations and environmental regulations, and other factors, many of which we are unable to control. If our cash flow is not sufficient to service our debt, we may be required to refinance the debt, sell assets, or sell shares of our stock on terms that we do not find attractive, if it can be done at all.

 

A portion of our borrowings from time to time may be at variable interest rates, making us vulnerable to increases in interest rates.

 

 

Our estimates of proved reserves at December 31, 2014 and 2013 have been prepared under SEC rules which could limit our ability to book additional proved undeveloped reserves in the future.

 

Estimates of our proved reserves as of December 31, 2014 and 2013 have been prepared and presented under the SEC’s rules relating to the reporting of oil and natural gas exploration activities. These rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This rule has limited and may continue to limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down any proved undeveloped reserves that are not developed within the required five-year timeframe.

 

Neither the estimated quantities of proved reserves nor the discounted present value of future net cash flows attributable to those reserves included in this Annual Report on Form 10-K are intended to represent their fair, or current, market value.

 

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

 

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. See “Business—Reserves—Estimated Proved Reserves” for information about our estimated oil and natural gas reserves and the PV-10 and standardized measure of discounted future net cash flows.

 

In order to prepare our estimates, we must project production rates, the extent of our eventual working and net revenue interests and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

 

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust estimates of our proved reserves to reflect production history, results of exploration and development, prevailing commodity prices and other factors, many of which are beyond our control.

 

It should not be assumed that the present value of future net revenues from our proved reserves is the current market value of our estimated reserves. We base the estimated discounted future net cash flows from our proved reserves using SEC regulations. Actual future prices and costs may differ materially from those used in the present value estimate.

 

5% of our total proved reserves as of December 31, 2014 consist of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced.

 

As of December 31, 2014, 4% of our total proved reserves were undeveloped and 1% were developed non-producing. Although we plan to develop and produce all our proved reserves, ultimately some may not be developed or produced. In addition, not all of the undeveloped or developed non-producing reserves may begin producing at the expected times or within budget.

 

Lower oil and natural gas prices and other factors have resulted in, and in the future may result in, ceiling test write-downs and other impairments of our asset carrying values.

 

We use the full cost method of accounting to report our oil and natural gas operations. Under this method, we capitalize the cost to acquire, explore for, and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of proved oil and natural gas properties may not exceed a “ceiling limit,” which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%. If net capitalized costs of proved oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling test write-down.” Under the accounting rules, we are required to perform a ceiling test each quarter. A ceiling test write-down would not impact cash flow from operating activities, but it would reduce our stockholders’ equity. For the years ended December 31, 2014 and 2013, the Company did not incur a ceiling test impairment. Declines in oil and natural gas prices could result in impairments of our oil and gas properties in future periods, See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies, Estimates, Judgments, and Assumptions—Full Cost Method of Accounting,” for further detail.

 

Investments in unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data relating to the properties. The amount of impairment assessed, if any, is added to the costs to be amortized in the appropriate full cost pool. If an impairment of unproved properties results in a reclassification to proved reserves, the amount by which the ceiling limit exceeds the capitalized costs of proved reserves would be reduced.

 

 

We assess the carrying amount of goodwill in the fourth quarter of each year and at other periods when events occur that may indicate an impairment exists. These events include, for example, a significant decline in oil and natural gas prices.

 

The risk that we will be required to write-down the carrying value of our oil and natural gas properties or our unproved properties increases when oil and natural gas prices are low. Oil prices have fallen significantly since reaching an average monthly high for the Company of $103.73 per barrel in June 2014, dropping to an average monthly low for the Company of $60.43 per barrel in December 2014. Oil prices have continued to decline during the first quarter of 2015, with the price of West Texas Intermediate crude oil falling below $43.00 a barrel in March 2015. In addition average natural gas prices received by the Company in December 2014 were approximately 10% lower compared to the high realized in mid-2014. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, or if estimated future development costs increase. Future write-downs of our full cost pool may be required if oil and natural gas prices decline, unproved property values decrease, estimated proved reserve volumes are revised downward or costs incurred in exploration, development, or acquisition activities in our full cost pool exceed the discounted future net cash flows from the additional reserves, if any, attributable to our cost pool.

 

Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our reserves.

 

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the development, exploitation, production and acquisition of oil and natural gas reserves. Cash used in investing activities related to acquisition, development and exploration expenditures was approximately $11.2 million and $9.6 million in 2014 and 2013, respectively.

 

The Company anticipates its budget for exploration and completion work on existing acreage will range between $2.0 million and $8.0 million for 2015 and will be highly dependent on prices that we receive for our oil and natural gas sales. We intend to finance future capital expenditures through cash flow from operations, and to the extent that it is prudent, from borrowings under our bank credit facility. However, our financing needs may exceed those resources, and thus require a substantial increase in capitalization through the issuance of debt or equity securities or sale or joint venturing of selected assets or delays in our planned exploration, development and completion activities. The issuance of additional indebtedness may require that a portion of operating cash flow be used to service the debt, thereby reducing the amount of cash flow available for other purposes. The actual amount and timing of future capital expenditures may differ materially from estimates as a result of, among other things, availability of personnel, commodity prices, actual drilling results, the availability of drilling rigs and other services, materials and equipment, and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures. Conversely, a significant improvement in product prices could result in an increase in our capital expenditures.

 

Our cash flow from operations and access to capital may be subject to a number of variables including the reliability of production, commodity prices, operating expenses, extraordinary and unanticipated expenses and the willingness and ability of our bank to lend.

 

Adverse events or trends related to these factors could reduce our ability to achieve or obtain the cash flow from operations, debt and/or equity capital necessary to sustain operations at current levels. Our Company, like the majority of smaller and mid-size independent oil and gas exploration companies, must continue acquiring and exploiting properties to replace depleting reserves, and the budget for these activities often will not be fully funded by operating cash flow. Accordingly, the inability to access outside capital could result in a curtailment of operations relating to the development of our properties, which in turn could lead to a decline in reserves and adversely affect the business, and our financial condition and results of operations.

 

Distressed economic conditions may adversely affect the collectability of trade receivables. Our accounts receivable are primarily from purchasers of our oil and natural gas production and other exploration and production companies that own working interests in the properties that we operate. This industry concentration could adversely impact our overall credit risk, because customers and working interest owners may be similarly affected by the same adverse changes. In addition, the possibility of a credit crisis and turmoil in financial markets could cause our commodity derivative instruments to be ineffective because a counterparty might be unable to perform its obligations.

 

We cannot be certain that funding, if needed, will be available to the extent required, or on acceptable terms. If we are unable to access funding when needed on acceptable terms, we may not be able to fully implement our drilling and development, complete new property acquisitions to replace reserves, take advantage of business opportunities, respond to competitive pressures, or refinance debt obligations as they come due, any of which could have a material adverse effect on our operations and financial results.

 

 

Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our potential drilling locations.

 

At an appropriate level of oil and natural gas prices, the Company has a multi-year drilling inventory of potential horizontal and vertical drilling locations on existing acreage. These locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, availability of qualified personnel, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering systems and pipeline transportation constraints, regulatory approvals and other factors. Accordingly, we cannot predict when or if the identified drilling locations will be drilled.

 

We could lose our undeveloped mineral leases if we don’t drill and complete wells in a timely manner.

 

Leased mineral properties give the holder the right to drill and complete wells in a timely manner. Leases have a contract term that is negotiated with the mineral owners. Generally, if a well is drilled and completed (thus “held by production”), the lease term continues so long as there is production from the well.

 

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years. Renewing leases on undrilled acreage may not be feasible due to increased cost or other reasons. If we are unable to renew leases on undrilled acreage, we would have to write off the initial acquisition cost of such acreage, which could be substantial and our reserve estimates and the financial information related thereto may be found to be inaccurate which could have a material adverse effect on us.

 

Some of these leases will only allow us to hold a portion of the lease even after one or more wells have been completed. As is customary in the oil and natural gas industry, Company management continually prioritizes the timing of drilling locations against drilling and completion costs, available capital, expected returns on capital, and lease expirations.

 

Unless we replace our reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

 

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. As a result, we must locate, acquire and develop new reserves to replace those being depleted by production. Unless we conduct successful ongoing exploration, development and exploitation activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future oil and natural gas reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations will be adversely affected.

 

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations.

 

Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development and production activities. Exploration, exploitation, development and production are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production. The Company’s decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see the Risk Factor “Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, drilling and completion costs may increase prior to completion of the project. Many factors may curtail, delay or cancel scheduled drilling projects, including:

 

	●	delays imposed by or resulting from compliance with regulatory requirements;
	●	pressure or irregularities in geological formations;
	●	shortages of or delays in obtaining equipment, materials and qualified personnel;
	●	equipment failures or accidents;
	●	adverse weather;
	●	declines in commodity prices;
	●	limited availability of financing at acceptable rates;
	●	title problems; and
	●	limitations in getting production to market due to transportation issues (see the Risk Factor entitled “Our business depends on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities would interfere with our ability to market the natural gas we produce.”)

 

 

Additionally, drilling, transportation and processing of hydrocarbons bear an inherent risk of loss of containment. Potential consequences include loss of reserves, loss of production, loss of economic value associated with an affected wellbore, contamination of soil, ground water, and surface water, as well as potential fines, penalties, or damages associated with any of the foregoing consequences.

 

As part of our ongoing operations, we sometimes drill in new or emerging plays. As a result, drilling in these areas is subject to greater risk and uncertainty.

 

We have technical personnel who are responsible for identifying new or emerging plays. These activities are more uncertain as to ultimate profitability than drilling in areas that are developed and have established production, because of little or sometimes no past drilling results by third parties to guide lease acquisition and drilling work. We cannot assure you that our future drilling activities in emerging plays will be successful or, if successful, will achieve the potential resource levels that we currently anticipate based on the drilling activities that have been completed, or that we will achieve the anticipated economic returns based on our current cost models.

 

Increasing costs could impact operating results.

 

Areas throughout the United States, including the Appalachian and Illinois Basins, are experiencing rising costs for drilling and completion rigs, pipe, cement, electrical power, and other goods and services. Over time, a failure of commodity prices to keep pace with the cost creep environment could adversely affect cash flow.

 

We may suffer losses or incur liability for events for which we or the operator of a property have chosen not to obtain insurance.

 

Our operations are subject to hazards and risks inherent in drilling, producing and transporting production, such as fires, natural disasters, explosions, pipeline ruptures, spills, and acts of terrorism, all of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other property damage. We maintain insurance coverage against some, but not all, potential losses, including hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. Concern has been expressed over the potential environmental impact of hydraulic fracturing operations, including the effect on water resources. We maintain liability insurance to protect us from claims or losses relating to hydraulic fracturing with a policy limit of $1.0 million in general liability, and a $5.0 million umbrella policy. Pollution and environmental risks generally are not fully insurable. Existing insurance coverage may not be renewed. Contractors who perform services may cause claims or losses that result in liability to us. The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on our business, financial condition and results of operations.

 

We may suffer losses or incur environmental liability in hydraulic fracturing operations.

 

Oil and natural gas deposits exist in shale and other formations. It is customary in our industry to recover oil and natural gas from these shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, underground where water, sand and other additives are pumped under high pressure into a shale formation. We contract with established service companies to conduct our hydraulic fracturing. The personnel of these service companies are trained to handle potentially hazardous materials and possess emergency protocols and equipment to deal with potential spills and carry Material Safety Data Sheets for all chemicals.

 

In the fracturing process, an accidental release could result in possible environmental damage. All wells have manifolds with escape lines to containment areas. High pressure valves for flow control are on the wellheads. Valves and piping are designed for higher pressures than are typically encountered. Piping is tested prior to any procedure and regular safety inspections and incident drill records are kept on those tests. Despite all of these safety procedures, there are many risks involved in hydraulic fracturing that could result in liability to the Company in excess of the Company’s policy limits, resulting in an adverse effect on our operations.

 

The use of derivative instruments used in hedging arrangements could result in financial losses or reduce income.

 

We may engage in the use of derivative instruments used in hedging arrangements for a significant part of production to reduce exposure to price fluctuations in commodity prices. These arrangements would expose the Company to risk of financial loss in some circumstances, including when production is less than expected, the counterparty to the hedging contract defaults on its contract obligations, or there is a change in the expected differential between the underlying price in the hedging agreement and the actual price received. In addition, these hedging arrangements may limit the benefits we would otherwise receive from increased commodity prices.

 

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced which could limit our ability to make future capital expenditures and to make payments on our indebtedness, which could also limit our ability to borrow funds. Future collateral requirements will depend on arrangements with our counterparties, volatile oil and natural gas prices and interest rates.

 

 

As of December 31, 2014, the fair value of the contracts with our derivatives counterparty was an asset of approximately $1.3 million. Any default by this counterparty on its obligations to us could have a material adverse effect on the Company’s financial condition and results of operations.

 

Our business depends on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities would interfere with our ability to market the natural gas we produce.

 

The marketability of our natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties. The amount of natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted transportation capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. We may be provided with only minimal, if any, notice as to when these circumstances will arise, or their duration. In addition, properties may be acquired which are not currently serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport the additional production. As a result, we may not be able to sell production from these properties until the necessary facilities are built.

 

We may incur losses as a result of title deficiencies.

 

We typically do not retain attorneys to examine title before acquiring leases or mineral interests. Prior to drilling a well, however, we (or the company that is the operator) obtain a preliminary title review to initially determine that no obvious title deficiencies are anticipated. As a result of some such examinations, certain curative work may be required to correct deficiencies in title, and such curative work may be expensive. In some instances, curative work may not be feasible or possible. In addition, it is possible that certain interests could have been bought in error from someone who is not the owner. In that event, our interest would be worthless.

 

In addition, the Company’s reserve estimates assume that we have proper title for the properties we have acquired. In the event we are unable to perform curative work to correct deficiencies and our interest is deemed to be worthless, our reserve estimates and the financial information related thereto may be found to be inaccurate, which could have a material adverse effect on us.

 

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

 

Our exploration, production and transportation operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations.

 

Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production and transportation of, oil and natural gas. Failure to comply with such laws and regulations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition and results of operations.

 

Changes to existing or new regulations may unfavorably impact the Company, could result in increased operating costs, and could have a material adverse effect on our financial condition and results of operations. For example, Congress is currently considering legislation that, if adopted in its proposed form, would subject companies involved in oil and natural gas exploration and production activities to, among other items, additional regulation of and restrictions on hydraulic fracturing of wells, the elimination of certain U.S. federal tax incentives and deductions available for such activities, and the prohibition or additional regulation of private energy commodity derivative and hedging activities. These and other potential regulations, particularly at the local level, could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which could in turn have a material adverse effect on our financial condition, results of operations and cash flows.

 

Operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.

 

We may incur significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our exploration, development and production activities. These delays, costs and liabilities could arise under a wide range of federal, state and local laws and regulations relating to protection of the environment, health and safety, including regulations and enforcement policies that have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. We are often required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that a proposed project may have on the environment, threatened and endangered species, and cultural and archaeological artifacts. The public may comment on and otherwise engage in the permitting process, including through judicial intervention. As a result, the permits we need may not be issued, or if issued, may not be issued in a timely manner or may impose requirements that restrict our ability to conduct operations.

 

 

In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Strict liability and joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken.

 

New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our business, financial condition or results of operations could be adversely affected.

 

The adoption of climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas we produce.

 

The U.S. Congress has considered legislation to mandate reductions of greenhouse gas emissions and certain states have already implemented, or may be in the process of implementing, similar legislation. Additionally, the U.S. Supreme Court has held in its decisions that carbon dioxide can be regulated as an “air pollutant” under the Clean Air Act, which could result in future regulations even if the U.S. Congress does not adopt new legislation regarding emissions. At this time, it is not possible to predict how legislation or new federal or state government mandates regarding the emission of greenhouse gases could impact our business; however, any such future laws or regulations could require us or our customers to devote potentially material amounts of capital or other resources in order to comply with such regulations. These expenditures could have a material adverse impact on our financial condition, results of operations, and cash flows.

 

Even though such legislation has not yet been adopted at the national level, regulatory agencies have begun taking actions to control and/or reduce emissions of greenhouse gases from oil and gas operations. In 2014, Colorado adopted strict emissions standards specific to the oil and gas industry. Although other states have yet to adopt similar standards, the EPA has announced plans to propose emissions regulations for the oil and gas industry in the summer of 2015. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.

 

Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

 

Essentially all of our reserves are subject to or have been subjected to hydraulic fracturing. The reservoir rock in these areas, in general, has insufficient permeability to flow enough oil or natural gas to be economically viable without stimulation. The controlling regulatory agencies for well construction have standards that are designed specifically in anticipation of hydraulic fracturing. The stimulation process cost varies according to well location and reservoir. It generally ranges from 10% of the well cost to 30%. To date, no incidents, citations or suits have resulted from our hydraulic fracturing operations. However, the regulatory environment is changing with respect to the use of hydraulic fracturing, and any increase in compliance costs could negatively impact our ability to conduct our business.

 

Since 2011, multiple bills have been introduced in the U.S. Congress, including three bills introduced in 2013, to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Another bill was introduced in the House in 2013 that would require sampling of groundwater sources of drinking water in conjunction with hydraulic fracturing activities. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. Sponsors of bills have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. None of the bills have been passed into law, and the 2013 bills all are still in committee.

 

Separately, the EPA has commenced the process of studying the possible relationship between hydraulic fracturing and drinking water and the first progress report was released in December 2012. A draft report is expected for public comment and peer review, but the current status of the report is uncertain. To receive input on the development of the draft study plan, the EPA held public meetings in four locations across the country in July and September 2010, which attracted hundreds of protestors. Also in September 2010, the EPA issued voluntary information requests to nine of the leading national and regional hydraulic fracturing service providers. Although eight of the nine hydraulic fracturing companies agreed to voluntarily compile and submit the information requested by the EPA, one company refused and the EPA issued a subpoena. Because of heightened public awareness and concern related to hydraulic fracturing, additional federal regulation by the EPA, Congress, or both is likely in the coming years. If adopted, such rules could lead to operational delays or increased operating costs and could result in additional regulatory burdens that would make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

  

 

The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

 

The recently enacted Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) is comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Commodity Futures Trading Commission (“CFTC”) and the SEC promulgated final and proposed rules and regulations implementing certain portions of the Dodd-Frank Act. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt similar rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may require us to comply with margin requirements and with certain clearing and trade-execution requirements, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative contracts to spin off some of their derivatives contracts to a separate entity, which may not be as creditworthy as the current counterparty. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including requirements to post collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower the commodity prices we realize. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.

Any laws or regulations that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

 

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.

 

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties. Also, there is substantial competition for investment capital in the industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition and results of operations.

 

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and field services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

 

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of qualified personnel, drilling and workover rigs, pipe and other equipment and materials as demand for rigs and equipment has increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition and results of operations.

 

The loss of senior management or technical personnel could adversely affect operations.

 

We depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel, including Patrick McDonald, our Chief Executive Officer, Mark Pierce, our President, Kevin Struzeski, our Chief Financial Officer, Treasurer and Secretary could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

 

 

During 2014, Mr. McDonald served as President and Chief Executive Officer of Forest Oil Corporation (“Forest”).

 

On June 21, 2012, Mr. McDonald was appointed interim Chief Executive Officer of Forest and on September 11, 2012, was appointed Forest’s permanent President and Chief Executive Officer. In response to Mr. McDonald’s permanent appointment, on October 4, 2012, the Company separated the offices of Chief Executive Officer, President and Chairman of the Board resulting in Mr. McDonald, who previously filled each of these offices, to continue as Chief Executive Officer with the office of Chairman of the Board filled by James H. Brandi and the office of President filled by Mr. Pierce.

 

Mr. McDonald served in the capacity of President and Chief Executive Officer of Forest until the completion of its business combination with Sabine Oil & Gas (“Sabine”) in December 2014. Mr. McDonald continues to serve as a director of Sabine.

 

The Company has limited control over activities on properties we do not operate, which could reduce our production and revenues.

 

A portion of our business is conducted through joint operating agreements under which we own partial interests in oil and gas properties. If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the underlying properties. The failure of an operator of our wells to adequately perform operations or an operator’s breach of the applicable agreements could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others, therefore, depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology. Because we do not have a majority interest in most wells that we do not operate, we may not be in a position to remove the operator in the event of poor performance.

 

We may be subject to risks in connection with acquisitions of properties.

 

The successful acquisition of producing properties requires an assessment of several factors, including:

 

	●	recoverable reserves;
	●	future commodity prices and their applicable differentials;
	●	operating costs; and
	●	potential environmental and other liabilities.

 

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even with inspections. Additionally, when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

 

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

 

In the future we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

 

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully, or to minimize any unforeseen operational difficulties could have a material adverse effect on the business, financial condition and results of operations.

 

 

We may incur more taxes and certain of our projects may become uneconomic if certain federal income tax deductions currently available with respect to oil and natural gas exploration and development are eliminated as a result of future legislation.

 

The passage of any legislation or any change in U.S. federal income tax law could eliminate certain tax deductions that are currently available with respect to oil and natural gas exploration and development. Any such change could negatively impact our financial condition and results of operations by increasing the costs we incur which would in turn make it uneconomic to drill some prospects if commodity prices are not sufficiently high, resulting in lower revenues and decreases in production and reserves.

 

We may incur additional expenses and costs due to environmental damages.

 

Our sites and equipment are susceptible to damage from environmental pressures such as flooding, tornadoes, hail, snow and other weather related issues. We may have to expend additional costs and expenses cleaning up areas damaged by weather related instances, such as repair roads, reinforce sites or repair damaged equipment. There is no assurance that our insurance will pay for all the damage created by such environmental pressures.

 

Risks Related to the Ownership of our Common Stock

 

We have incurred and will continue to incur increased costs and demands upon management and accounting and finance resources as a result of complying with the laws and regulations affecting public companies; any failure to establish and maintain adequate internal control over financial reporting or to recruit, train and retain necessary accounting and finance personnel could have an adverse effect on our ability to accurately and timely prepare our Consolidated Financial Statements.

 

As a public operating company, we incur significant administrative, legal, accounting and other burdens and expenses beyond those of a private company, including those associated with corporate governance requirements and public company reporting obligations. In particular, we have had to and will continue to expend resources to supplement our internal accounting and financial resources to obtain technical and public company training and expertise, as well as refine our quarterly and annual financial statement closing process, to enable us to satisfy such reporting obligations. However, even if we are successful in doing so, there can be no assurance that our finance and accounting organization will be able to adequately meet the increased demands that result from being a public company.

 

Our management team must comply with various requirements of being a public company. We have devoted, and will continue to devote, significant resources to address these public company-associated requirements, including compliance programs and investor relations, as well as our financial reporting obligations. Complying with these rules and regulations has and will substantially increase our legal and financial compliance costs and make some activities more time-consuming and costly.

 

An active, liquid and orderly trading market for our common stock may not develop, and the price of our stock may be volatile and may decline in value.

 

There currently is not an active public market for our common stock. An active trading market may not develop or, if developed, may not be sustained. The lack of an active market may impair your ability to sell your shares of common stock at the time you wish to sell them or at a price that you consider reasonable. An inactive market may also impair our ability to raise capital by selling shares of common stock and may impair our ability to acquire other companies or assets by using shares of our common stock as consideration.

 

Our common stock may not be eligible for listing on a national securities exchange.

 

Our common stock is not currently listed on a national securities exchange, and we do not currently meet the initial quantitative listing standards of a national securities exchange. We cannot assure you that we will be able to meet the initial listing standards of any national securities exchange, or, if we do meet such initial qualitative listing standards, that we will be able to maintain any such listing. Until our common stock is listed on a national securities exchange, we expect that it will continue to be eligible and quoted on the OTCQB. In those venues, however, an investor may find it difficult to obtain accurate quotations as to the market value of our common stock. In addition, if we fail to meet the criteria set forth in SEC regulations, various requirements would be imposed by law on broker-dealers who sell our securities to persons other than established customers and accredited investors. Consequently, such regulations may deter broker-dealers from recommending or selling our common stock, which may further affect its liquidity. This would also make it more difficult for us to raise additional capital.

  

Our common stock may be considered a “penny stock.”

 

The SEC has adopted regulations which generally define “penny stock” to be an equity security that has a market price of less than $5.00 per share, subject to specific exemptions. The market price of our common stock may be less than $5.00 per share and therefore may be a “penny stock.” Broker and dealers effecting transactions in “penny stock” must disclose certain information concerning the transaction, obtain a written agreement from the purchaser and determine that the purchaser is reasonably suitable to purchase the securities. These rules may restrict the ability of brokers or dealers to sell our common stock and may affect your ability to sell shares of our common stock in the future.

 

 

Control of our stock by current stockholders is expected to remain significant.

 

Currently, our directors directly and indirectly beneficially own a majority of our outstanding common stock. As a result, these affiliates have the ability to exercise significant influence over matters submitted to our stockholders for approval, including the election and removal of directors, amendments to our certificate of incorporation and bylaws and the approval of any business combination. This concentration of ownership may also have the effect of delaying or preventing a change of control of our company or discouraging others from making tender offers for our shares, which could prevent our stockholders from receiving a premium for their shares.

 

It is not likely that we will pay dividends.

 

We currently intend to retain our future earnings to support operations and to finance expansion and, therefore, we do not anticipate paying any cash dividends to holders of our common stock in the foreseeable future.

 

Terms of subsequent financings may adversely impact stockholder equity.

 

We may have to raise additional equity or debt in the future. In that event, the value of the stockholders’ equity in common stock could be reduced. For example, if we issue debt securities, the holders of the debt would have a claim to our assets that would be prior to the rights of shareholders until the debt is paid. Interest on these debt securities would increase costs and could negatively impact operating results.

 

The borrowing base under our secured lending facility presently is $20 million and all borrowings under the facility are secured by a majority of our oil and natural gas assets. Borrowings outside the facility may have to be unsecured, and accordingly, such borrowings, if obtainable, would have a higher interest rate, which would increase debt service and more negatively impact operating results.

 

Preferred stock could be issued in series from time to time with such designations, rights, preferences, and limitations as needed to raise capital. The terms of preferred stock will be determined by our Board of Directors and could be more advantageous to those investors than to the holders of common stock. In addition, if we need to raise more equity capital from sale of common stock, institutional or other investors may negotiate terms more favorable than the then current price of Company’s common stock.

 

The Company’s Certificate of Incorporation does not provide shareholders the pre-emptive right to buy shares from the Company. As a result, stockholders will not have the automatic ability to avoid dilution in their percentage ownership of the Company.

 

Item 1B.    Unresolved Staff Comments

 

None.

 

Item 2.    Properties.

 

Information on Properties is contained in Item 1 of this Annual Report on Form 10-K.

 

Item 3.    Legal Proceedings.

 

The Company is subject to legal claims and proceedings in the ordinary course of its oil and natural gas exploration and production business. Management believes that none of the current pending proceedings would have a material adverse effect on the Company, should the controversies be resolved against the Company.

 

Item 4.    Mine Safety Disclosures.

 

Not applicable.

 

 

PART II

 

Item 5.    Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Common Stock

 

Carbon has one class of common shares outstanding, its common stock, par value $0.01 per share ("Common Stock"). Our common stock is quoted through the OTC Markets (“OTCQB”) under the symbol CRBO. However, the limited and sporadic quotations of our stock may not constitute an established trading market for our stock. There can be no assurance that an active market will develop for our common stock in the future. The table below sets forth the high and low bid prices per share of our common stock as quoted on the OTCQB for the periods indicated. All OTCQB quotations included herein reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.

 

Year Ended December 31,				Quarter				High				Low
	2014				First			$	0.94			$	0.66
					Second			$	0.94			$	0.53
					Third			$	0.98			$	0.83
					Fourth			$	0.90			$	0.63
	2013				First			$	0.67			$	0.41
					Second			$	0.94			$	0.50
					Third			$	0.90			$	0.60
					Fourth			$	0.90			$	0.75

  

As of March 17, 2015, the closing price for our common stock on the OTCQB was $0.70 per share.

 

Holders

 

As of March 17, 2015, there were approximately 1,100 holders of record of our common stock. The number of holders does not include the shareholders for whom shares are held in a "nominee" or "street" name.

 

Dividend Policy and Restrictions

 

We have not paid any cash dividends on our common stock to date. The payment of dividends in the future will be contingent upon our revenues and earnings, if any, capital requirements and general financial condition, and will be within the discretion of our then-existing Board of Directors. We currently intend to retain our future earnings to support operations and to finance expansion and, therefore, our Board of Directors does not anticipate paying any cash dividends to holders of our common stock in the foreseeable future.

 

The Company’s ability to pay distributions is currently limited by:

 

	●	The terms of our credit facility with the Bank of Oklahoma that prohibit us from paying dividends on our common stock while amounts are owed to the Bank of Oklahoma; and
	●	Delaware General Corporation Law which provides that a Delaware corporation may pay dividends either: 1) out of the corporation's surplus (as defined by Delaware law); or 2) if there is no surplus, out of the corporation's net profit for the fiscal year in which the dividend is declared or the preceding fiscal year. Any determination in the future to pay dividends will depend on the Company's financial condition, capital requirements, results of operations, contractual limitations, legal restrictions and any other factors the Board of Directors deem relevant.

 

Securities Authorized for Issuance Under Compensation Plans

 

Our Board of Directors has adopted the 2011 Stock Incentive Plan (the “Plan”) under which 12,600,000 shares of common stock are authorized for issuance. On December 8, 2011, the stockholders approved the adoption of the Plan at Carbon’s annual meeting of shareholders. See Note 8 of the Consolidated Financial Statements for a description of compensation plans adopted without the approval of the shareholders.

 

Upon closing the Merger, the Company assumed outstanding options granted prior to the Merger to acquire 342,459 shares of common stock. At the time of the Merger such options became exercisable to acquire Company common stock and the terms of the options were amended to reflect the exchange ratio used to effect the Merger. The following is provided with respect to compensation plans (including individual compensation arrangements) under which equity securities are authorized for issuance as of December 31, 2014:

  

Equity Compensation Plan Information
										Number of Securities
										Remaining Available
		Number of Securities								for Future Issuance
		to be Issued Upon				Weighted-Average				Under Equity
		Exercise of				Exercise Price of				Compensation Plans
		Outstanding Options,				Outstanding Options,				(Excluding Securities
Plan Category		Warrants, and Rights				Warrants, and Rights(3)				Reflected in Column (a))
and Description		(a)				(b)				(c)
Equity Compensation Plans
Approved by Security Holders (1)			4,686,160				-			3,103,840
Equity Compensation Plans Not
Approved by Security Holders			163,076	(2)		$	0.61			-
Total			4,849,236			$	0.61			3,103,840

 

(1)	On December 8, 2011 the Company’s shareholders approved the adoption of the Company’s 2011 Stock Incentive Plan under which 12,600,000 shares were reserved for issuance. For each of the years ended December 31, 2014 and 2013, the Company granted 1,600,000 shares of restricted stock. As of December 31, 2014, there are approximately 3.2 million shares of unvested restricted stock. For the years ended December 31, 2014 and 2013, the Company granted 1,600,000 and 1,920,000 restricted performance units, respectively. As of December 31, 2014, there are approximately 4.7 million shares of unvested performance units.
(2)	Consists of options granted prior to the Merger by Nytis USA to an officer of the Company. All of these options were assumed by the Company at the time of the Merger.
(3)	The weighted average exercise price in column (b) excludes the restricted performance units.

  

Unregistered Sales of Equity Securities

 

All sales of unregistered equity securities that occurred during the period covered by this report, and through December 31, 2014, have been previously reported in a Quarterly Report on Form 10-Q or a Current Report on Form 8-K.

 

Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations.

 

The following discussion includes forward-looking statements about our business, financial condition and results of operations, including discussions about management’s expectations for our business. These statements represent projections, beliefs and expectations based on current circumstances and conditions and in light of recent events and trends, and you should not construe these statements either as assurances of performance or as promises of a given course of action. Instead, various known and unknown factors are likely to cause our actual performance and management’s actions to vary, and the results of these variances may be both material and adverse. A description of material factors known to us that may cause our results to vary, or may cause management to deviate from its current plans and expectations, is set forth under “Risk Factors.” See “Cautionary Note Regarding Forward-Looking Statements.” The following discussion should also be read in conjunction with our Consolidated Financial Statements, including the notes thereto appearing elsewhere in this Annual Report on Form 10-K.

 

 

Carbon is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of oil and natural gas properties located in the Appalachian and the Illinois Basin of the United States. We focus on conventional and unconventional reservoirs, including shale, tight sand 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 December 31, 2014, our proved developed reserves were comprised of 12% oil and 88% natural gas. Our financial results are sensitive to fluctuations in natural gas prices. Our current capital expenditure program is focused on the development of our oil 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 reserves;
	●	Development of oil and natural gas projects that we believe will generate attractive risk adjusted rates of return;
	●	Development and maintenance of a portfolio of low risk, long-lived oil and natural gas properties that provide stable cash flows; and
	●	Property and land acquisitions that complement our core producing areas.

 

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. The following table highlights the quarterly average of NYMEX price trends for oil and natural gas prices since the first quarter of 2013:

 

		2013																2014
		Q1				Q2				Q3				Q4				Q1				Q2				Q3				Q4
Oil (Bbl)		$	94.34			$	94.23			$	105.82			$	97.50			$	98.62			$	102.98			$	97.21			$	73.12
Natural Gas (MMBtu)		$	3.34			$	4.10			$	3.58			$	3.60			$	4.93			$	4.68			$	4.07			$	4.04

 

Oil prices have fallen significantly since reaching an average monthly high for the Company of $103.73 per barrel in June 2014, dropping to an average monthly low for the Company of $60.43 per barrel in December 2014. Oil prices have continued to decline during the first quarter of 2015, with the price of West Texas Intermediate crude oil falling below $43.00 a barrel in March 2015. In addition, average natural gas prices received by the Company in December 2014 were approximately 10% lower compared to the high realized in mid-2014. Lower oil and natural gas prices may not only decrease our revenues, but may also reduce the amount of oil and natural gas that the Company can produce economically and potentially lower our oil and natural gas reserves. A substantial or extended decline in oil or natural gas prices may result in future impairments of our proved reserves and may materially and adversely affect our future business, financial condition, cash flows, results of operations or liquidity. Lower oil and natural gas prices may also reduce the amount of borrowing base under our bank credit facility, which is determined at the discretion of our lender.

 

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

 

Operational Highlights

 

At December 31, 2014, we had approximately 274,000 net acres of mineral leases located in the Appalachian and Illinois Basins of the United States. Approximately 50% of this acreage is held by production and of the remaining leases, approximately 37% 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 towards a Berea Sandstone horizontal oil drilling program in eastern Kentucky and western West Virginia. As of December 31, 2014, we have over 43,000 net mineral acres in the region. Since 2010, we have drilled 51 horizontal wells in the program. During the program, we have enhanced our well performance and have improved well drilling and completion performance measures, including reduced drilling days, increased horizontal lateral length, decreased cost per frac stage and reduced days from spud to first production. In addition, we have established an infrastructure of oil and natural gas gathering and salt water handling and disposal facilities which will benefit the economics of future drilling. We continue to acquire leases and producing properties where we have identified additional potential to expand our activities.

 

 

Another area of focus is coal bed methane in Illinois. A second horizontal well has been drilled and is under evaluation. The Company has 23,000 acres in the play.

 

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

 

On December 15, 2014, Nytis LLC together with Liberty, (the “Sellers”) completed a preliminary closing in accordance with a Purchase and Sale Agreement (the “PSA”) entered into on October 15, 2014, as amended, 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 (the “Leases”).

 

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 closing of this transaction, Nytis LLC received approximately $12.4 million in cash with the proceeds from the sale recorded as a reduction of the Company’s investment in its proved and unevaluated oil and natural gas properties.

 

At the preliminary closing, the buyer provided to Sellers a description of title defects and estimated that the extent of title defects was less than the twenty percent (20%) threshold provided in the PSA that would have permitted either buyer or Sellers to terminate the transaction.

 

A final closing is scheduled for mid-April 2015 at which time the Sellers’ curative work and substitute acreage will be agreed to and may result in a downward revision of the purchase price.

 

Pursuant to a stock purchase agreement dated June 9, 2014, the Company purchased approximately 8.2 million shares of the Company’s common stock from a shareholder for a purchase price of $0.40 per share for aggregate consideration of approximately $3.3 million.

 

On February 25, 2014, Nytis LLC entered into a participation agreement with Liberty Energy LLC (“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 will 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 December 31, 2014, Liberty had participated in drilling of six horizontal wells pursuant to this agreement.

  

Principal Components of Our Cost Structure

 

	●	Lease operating and gathering, compression and transportation expenses.  These are costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workover expenses related to our oil and natural gas properties.
	●	Production taxes.  Production taxes consist of severance and ad valorem taxes and are paid on oil and natural gas produced based on a percentage of market prices or at fixed rates established by federal, state or local taxing authorities.
	●	Depreciation, depletion, amortization and impairment. The Company uses the full cost method of accounting for oil and gas properties. All costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment are capitalized. The Company historically has performed a quarterly ceiling test. The full cost ceiling test is a limitation on capitalized costs prescribed by the SEC. The ceiling test is not a fair value based measurement, rather it is a standardized mathematical calculation that compares the net capitalized costs of the Company’s full cost pool to estimated discounted cash flows. Should the net capitalized cost exceed the sum of the estimated discounted cash flows, a ceiling test write-down would be recognized to the extent of the excess.

 

 

		The Company performs its ceiling tests based on average first-of-the-month prices during the twelve-month period prior to the reporting date. For the years ended December 31, 2014 and 2013, the Company did not incur a ceiling test impairment.
		Depletion is calculated using the capitalized costs in the full cost pool, including estimated asset retirement costs and the estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values and depleted based on a unit-of-production method.
	●	General and administrative expense.  These costs include payroll and benefits for our corporate staff, costs of maintaining our offices, costs of managing our production and development operations, franchise taxes, audit, tax, legal and other professional fees and legal compliance.
	●	Interest expense.  We finance a portion of our working capital requirements and acquisitions with borrowings under our bank credit facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions.
	●	Income tax expense.  We are subject to state and federal income taxes but historically have not been in a tax paying position for regular federal income taxes, primarily due to the current deductibility of intangible drilling costs (“IDC”) and net operating loss (“NOL”) carryforwards. We pay alternative minimum tax, state income or franchise taxes where IDC or NOL deductions do not exceed taxable income or where state income or franchise taxes are determined on another basis. The Company has generated NOL carryforwards which expire starting in 2031 through 2033. The amount of deferred tax assets considered realizable could change based on estimates of future income or loss.

 

 

Results of Operations

 

The following discussion and analysis relates to items that have affected our results of operations for the years ended December 31, 2014 and 2013. The following table sets forth for the periods presented selected historical statements of operations data. The information contained in the table should be read in conjunction with the Company’s Consolidated Financial Statements and the information under “Forward Looking Statements” above.

  

		Twelve Months Ended
		December 31,								Percent
(in thousands except per unit data)		2014				2013				Change
Revenue:
Oil and natural gas sales		$	22,505			$	18,681				20	%
Commodity derivative gain (loss)			1,246				(459	)			*
Other income			325				416				-22	%
Total revenues			24,076				18,638				29	%
Expenses:
Lease operating expenses			3,333				2,620				27	%
Transportation costs			1,808				1,609				12	%
Production and property taxes			1,656				1,258				32	%
General and administrative			6,133				5,151				19	%
Depreciation, depletion and amortization			2,954				2,922				1	%
Accretion of asset retirement obligations			117				138				-15	%
Total expenses			16,001				13,698				17	%
Operating income		$	8,075			$	4,940				65	%
Other income and (expense):
Interest expense		$	(472	)		$	(581	)			-18	%
Equity investment (loss) income			8				(91	)			*
Total other expenses and income		$	(464	)		$	(672	)			-31	%
Production data:
Natural gas (MMcf)			2,138				2,252				-5	%
Oil and liquids (MBbl)			134				107				25	%
Combined (MMcfe)			2,942				2,894				2	%
Average prices before effects of hedges:
Natural gas (per Mcf)		$	4.83			$	3.76				28	%
Oil and liquids (per Bbl)		$	91.07			$	95.49				-5	%
Combined (per Mcfe)		$	7.65			$	6.46				19	%
Average prices after effects of hedges**:
Natural gas (per Mcf)		$	5.17			$	3.69				40	%
Oil and liquids (per Bbl)		$	94.94			$	92.80				2	%
Combined (per Mcfe)		$	8.07			$	6.30				28	%
Average costs (per Mcfe):
Lease operating expenses		$	1.13			$	0.91				24	%
Transportation costs		$	0.61			$	0.56				9	%
Production and property taxes		$	0.56			$	0.43				30	%
Depreciation, depletion and amortization		$	1.00			$	1.01				-1	%

 

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

 

Oil and natural gas sales- Revenues from sales of oil and natural gas increased 20% to approximately $22.5 million for the year ended December 31, 2014 from approximately $18.7 million for the year ended December 31, 2013. A 19% increase in oil revenues resulted from a 25% increase in production, partially offset by a 5% decrease in average prices. The increase in oil production is attributed to the Company’s focus on developing its oil properties in the Berea Sandstone formation in the Appalachian Basin. The decrease in average oil prices is principally attributed to a sharp decline in oil prices during the last three months of 2014. The Company’s average oil prices declined approximately 42% for the month of December 2014 from its high in June 2014. Natural gas revenues in the year ended December 31, 2014 increased 22% over the same period in 2013 primarily due to a 28% increase in natural gas prices partially offset by a 5% decrease in gas volumes sold. Average natural gas prices were approximately 10% lower for the month of December 2014 compared with the high realized in mid-2014.

 

 

Commodity derivative gains (losses)- To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations which we experienced in the last three months of 2014, we enter into derivative contracts using fixed price swap contracts when our management believes that available futures prices for our oil and natural gas production are sufficient to warrant hedging to ensure predicable cash flows for certain of the Company’s production. Because we do not designate these derivatives as cash flow hedges, they do not receive hedge accounting treatment and all mark-to-market gains or losses 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 years ended December 31, 2014 and 2013, we had hedging gains of approximately $1.2 million and hedging losses of $459,000, respectively. Due to significant declines in oil commodity prices in the last quarter of 2014, the market-to-market value of our current fixed priced commodity derivative positions settling in 2015 and 2016 resulted in an unrealized derivative asset of approximately $1.3 million at December 31, 2014 and unrealized gains of approximately $1.6 million for the year ended December 31, 2014 as compared with unrealized losses of approximately $239,000 for the year ended December 31, 2013.

 

Lease operating expenses- Lease operating expenses for the year ended December 31, 2014 increased 27% compared to the year ended December 31, 2013. On a per Mcfe basis, lease operating expenses increased from $0.91 per Mcfe for the year ended December 31, 2013 to $1.13 per Mcfe for the year ended December 31, 2014, primarily due to the increase in oil production relative to natural gas. Operating costs for oil producing properties are generally higher than for gas producing properties due to various factors including water disposal, well maintenance and other costs associated with oil producing properties. For the year ended December 31, 2014, the Company incurred additional lease operating expenses for lease maintenance associated with winter damage and costs associated with bringing new wells on production.

 

Transportation costs- Transportation costs increased 12% from approximately $1.6 million for the year ended December 31, 2013 to approximately $1.8 million for the year ended December 31, 2014. On a per Mcfe basis, these expenses increased from $0.56 per Mcfe for the year ended December 31, 2013 to $0.61 per Mcfe for the year ended December 31, 2014. This increase is primarily due to new transportation contracts entered into during the fourth quarter of 2013.

 

Production and property taxes- Production and property taxes increased from approximately $1.3 million for the year ended December 31, 2013 to approximately $1.7 million for the year ended December 31, 2014. This increase is primarily attributed to an increase in revenues. Production taxes are generally calculated as a percentage of sales revenue, which averages approximately 4.4% for the Company. Ad valorem taxes rates, which can fluctuate by year, are determined by individual counties where the Company has production and are assessed on the Company’s sales revenues one or two years in arrears depending upon the location of the production.

 

Depreciation, depletion and amortization (DD&A)- DD&A for 2014 increased approximately 1% as compared to the same period in 2013. On a per Mcfe basis, DD&A decreased from $1.01 per Mcfe for the year ended December 31, 2013 to $1.00 per Mcfe for the year ended December 31, 2014. This decrease is primarily attributed to a reduction in the depletable asset base caused by the proceeds from the sale of oil and gas assets, partially offset by capital expenditures incurred during 2014.

 

General and administrative expenses- General and administrative expenses for the year ended December 31, 2014 increased 19% from the same period in 2013. As shown in the table below, additional stock-based compensation, a non-cash expense, increased 63% and other general and administrative expenses increased 10% for the year ended December 31, 2014 compared to the same period in 2013. The increase in stock-based compensation for the year ended December 31, 2014 compared to the same period in 2013 is due to restricted stock granted during 2014. The increase in other general and administrative expenses is primarily attributed to personnel related costs and costs associated with the participation agreement with Liberty and the purchase and sale agreement related to the sale of the Company’s deep rights in certain leases located in Kentucky and West Virginia.

 

		2014				2013				Increase
General and administrative expenses
(in thousands)
Stock-based compensation		$	1,492			$	913			$	579
Other general and administrative expenses			4,641				4,238				403
Total general and administrative expenses		$	6,133			$	5,151			$	982

 

 

Interest expense- Interest expense decreased from approximately $581,000 for the year ended December 31, 2013 to approximately $471,000 for the year ended December 31, 2014 primarily due to lower average effective interest rates during 2014 as compared to 2013 as the Company negotiated the elimination of the interest rate floor in its credit agreement in June 2013. In December 2014, the Company reduced its outstanding loan balance to approximately $2.1 million as of December 31, 2014 with the proceeds from the sale of its deep rights in certain leases located in Kentucky and West Virginia.

 

Liquidity and Capital Resources

 

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

 

Changes in the market prices for oil and natural gas directly impact our level of cash flow generated from operations. We employ a commodity hedging strategy as an attempt to moderate the effects of wide fluctuations in commodity prices on our cash flow. As of December 31, 2014, we have outstanding natural gas hedges of 750,000 MMbtu for 2015 at an average price of $4.05 per MMbtu and 40,000 MMBtu for 2016 at an average price of $4.20 per MMBtu in addition to oil hedges of 10,000 barrels for 2015 at an average price of $94.66. 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 and 2016. However, future hedging activities may result in reduced income or even financial losses to us. See “Risk Factors—Our future use of hedging arrangements could result in financial losses or reduce income,” 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 December 31, 2014, our derivative counterparty was party to our credit facility, or its affiliates.

 

The other primary source of liquidity is our credit facility (described below), which had an aggregate borrowing base of $20.0 million of which $17.9 million was available as of December 31, 2014. 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 approximately $2.1 million drawn on our credit facility as of December 31, 2014.

 

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 net cash provided by operating activities may be adversely affected by continued low commodity prices. We believe that our expected future cash flows provided by operating activities, the $17.9 million of additional borrowing capacity available under our credit facility as of December 31, 2014 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 a deterioration in domestic and global economic conditions or the continuation of the recent significant decline in oil and natural gas 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,” 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 December 31, 2014 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 May 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. Prior to July 2013, for all outstanding debt, regardless if the loan was based on the Alternative Base Rate or LIBOR, there was a minimum floor of 4.5% per annum. In June 2013, the Company and Bank of Oklahoma amended the credit agreement whereby the Company’s loans under the credit agreement were no longer subject to the minimum interest rate floor for LIBOR tranches commencing after July 25, 2013 and loan amounts subject to the Alternative Base Rate after July 31, 2013.

 

 

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

 

Of the $50.0 million total nominal amount under the Credit Facility, Bank of Oklahoma holds 100% of the total commitments. As of December 31, 2014 there was approximately $2.1 million in borrowings under the Credit Facility. The Company’s effective borrowing rate at December 31, 2014 was approximately 3.0%.

 

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. In June 2013, an amendment to the credit agreement increased the maximum line of credit available under hedging arrangements from $8.0 million to $9.5 million.

 

Historical Cash Flow

 

Net cash provided by (used in) operating, investing and financing activities for the years ended December 31, 2014 and 2013 were as follows:

 

		Years Ended
		December 31,
(in thousands)		2014				2013
Net cash provided by operating activities		$	11,696			$	7,848
Net cash provided by (used in) investing activities		$	3,623			$	(9,516	)
Net cash (used in) provided by financing activities		$	(14,430	)		$	1,583

 

Net cash provided by operating activities is primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and changes in working capital. Operating cash flows increased approximately $3.8 million for the year ended December 31, 2014 as compared to the year ended December 31, 2013, primarily due to a 25% increase in oil sales volumes and a 28% increase in natural gas revenues.

 

Net cash provided by (used in) investing activities is primarily comprised of the acquisition, exploration, and development of oil and natural gas properties, net of dispositions of oil and natural gas properties. The increase in investing cash flows of approximately $13.1 million for the year ended December 31, 2014 as compared to the year ended December 31, 2013 was primarily due to proceeds of approximately $12.4 million received pursuant to the sale of the Company’s deep rights in certain leases located in Kentucky and West Virginia, and proceeds of approximately $2.8 million received from the sale of oil and gas properties relating to the participation agreement with Liberty, partially offset by an increase in capital expenditures of approximately $1.6 million.

 

The decrease in financing cash flows of approximately $16.0 million for the year ended December 31, 2014 as compared to the year ended December 31, 2013 was primarily due to the purchase of approximately 8.2 million shares of the Company’s common stock for approximately $3.3 million and payments resulting in a reduction of approximately $10.7 million in amounts due under the Company’s Credit Facility.

 

 

Capital Expenditures

 

Capital expenditures for the years ended December 31, 2014 and 2013 are summarized in the following table:

 

		Years Ended December 31,
(in thousands)		2014				2013
Acquisition of oil and gas properties:
Unevaluated properties		$	2,166			$	1,117
Oil and natural gas producing properties			78				501
Drilling and development			8,685				7,818
Pipeline and gathering			144				1
Other			172				178
Total capital expenditures		$	11,245			$	9,615

 

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

 

Due to the expected higher rate of return on invested capital on oil wells versus natural gas wells, the Company’s capital expenditure program has, since 2012, focused principally on the development of its oil prospects. In addition, we managed our capital expenditures by keeping our exploration and development capital spending near our cash flows. We were able to expand our oil drilling program in 2014 and 2013 by entering into two separate drilling programs with Liberty, one in 2012 and the other in 2014, in which Liberty has or will pay a disproportionate percentage of costs associated with the drilling and completion of 20 wells in each of the drilling programs. 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.

 

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 December 31, 2014, the off-balance sheet arrangements and transactions that we have entered into include (i) operating lease agreements, (ii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as natural gas transportation commitments, and (iii) oil and natural gas physical delivery contracts that are not expected to be net cash settled and are considered to be normal sales contracts and not derivatives. We do not believe that any of these arrangements are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.

 

Critical Accounting Policies, Estimates, Judgments, and Assumptions

 

Carbon prepares its financial statements and the accompanying notes in conformity with accounting principles generally accepted in the United States of America, which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompany notes. Carbon identifies certain accounting policies as critical based on, among other things, their impact on the portrayal of Carbon’s financial condition, results of operations, or liquidity and the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. The following is a discussion of Carbon’s most critical accounting policies.

 

Full Cost Method of Accounting

 

The accounting for our business is subject to special accounting rules that are unique to the oil and natural gas industry. There are two allowable methods of accounting for oil and natural gas business activities: the full cost method and the successful efforts method. The differences between the two methods can lead to significant variances in the amounts reported in financial statements. The Company uses the full cost method of accounting as defined by SEC Release No. 33-8995 and FASB ASC 932.

 

Under the full cost method, separate cost centers are maintained for each country in which we incur costs. All costs incurred in the acquisition, exploration, and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes, and overhead related to exploration and development activities) are capitalized. The fair value of estimated future costs of site restoration, dismantlement, and abandonment activities is capitalized, and a corresponding asset retirement obligation liability is recorded.

 

Capitalized costs applicable to each full cost center are depleted using the units-of-production method based on conversion to common units of measure using one barrel of oil as an equivalent to six thousand cubic feet of natural gas. Changes in estimates of reserves or future development costs are accounted for prospectively in the depletion calculations. Based on this accounting policy, our December 31, 2014 and 2013 reserves estimates were used for our respective period depletion calculations. These reserves estimates were calculated in accordance with SEC rules. See “Business—Reserves” and Notes 1 and 2 to the Consolidated Financial Statements for a more complete discussion of the rule and our estimated proved reserves as of December 31, 2014 and 2013.

 

 

Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test for each cost center. 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 test determines a limit, or ceiling, on the book value of our oil and natural gas properties. That limit is basically the after tax present value of the future net cash flows from proved oil and natural gas reserves. This ceiling is compared to the net book value of the oil and natural gas properties reduced by any related net deferred income tax liability. If the net book value reduced by the related deferred income taxes exceeds the ceiling, an impairment or non-cash write-down is required. The two primary factors impacting this test are reserve levels and oil and natural gas prices and their associated impact on the present value of estimated future net revenues. Oil prices have fallen significantly since reaching an average monthly high for the Company of $103.73 per barrel in June 2014, dropping to an average monthly low for the Company of $60.43 per barrel in December 2014. Oil prices have continued to decline during the first quarter of 2015, with the price of West Texas Intermediate crude oil falling below $43.00 a barrel in March 2015. In addition, average natural gas prices received by the Company in December 2014 were approximately 10% lower compared to the high realized in mid-2014. Lower oil and natural gas prices may not only decrease our revenues, but may also reduce the amount of oil and natural gas that the Company can produce economically and potentially lower our oil and natural gas reserves. Negative revisions to estimates of oil and natural gas reserves and decreases in prices can have a material impact of the present value of estimated future net revenues which may require us to recognize an impairment of our oil and natural gas properties in future periods. For the years ended December 31, 2014 and 2013, the Company did not incur a ceiling test impairment.

 

In countries or areas where the existence of proved reserves has not yet been determined, leasehold costs, seismic costs, and other costs incurred during the exploration phase remain capitalized as unproved property costs until proved reserves have been established or until exploration activities cease. Investments in unproved properties are not depleted pending the determination of the existence of proved reserves. If exploration activities result in the establishment of proved reserves, amounts are reclassified as proved properties and become subject to depreciation, depletion, and amortization, and the application of the ceiling limitation. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practicable to individually assess properties whose costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized in the appropriate full cost pool.

 

Under the alternative successful efforts method of accounting, surrendered, abandoned, and impaired leases, delay lease rentals, exploratory dry holes, and overhead costs are expensed as incurred. Capitalized costs are depleted on a property-by-property basis. Impairments are also assessed on a property-by-property basis and are charged to expense when assessed.

 

The full cost method is used to account for our oil and natural gas exploration and development activities, because we believe it appropriately reports the costs of our exploration programs as part of an overall investment in discovering and developing proved reserves.

 

Oil and Natural Gas Reserve Estimates

 

Our estimates of proved reserves are based on the quantities of oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, production and property taxes, development costs, and workover costs, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. Despite the inherent uncertainty in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of-production method to amortize our oil and natural gas properties, the quantity of reserves could significantly impact our DD&A expense. Our oil and natural gas properties are also subject to a “ceiling test” limitation based in part on the quantity of our proved reserves.

 

Reference should be made to “Reserves” under “Description of Business,” and “Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves,” under “Risk Factors”.

 

Accounting for Derivative Instruments

 

We recognize all derivative instruments as either assets or liabilities at fair value. Under the provisions of authoritative derivative accounting guidance, we may or may not elect to designate a derivative instrument as a hedge against changes in the fair value of an asset or a liability (a “fair value hedge”) or against exposure to variability in expected future cash flows (a “cash flow hedge”). The accounting treatment for the changes in fair value of a derivative instrument is dependent upon whether or not a derivative instrument is a cash flow hedge or a fair value hedge, and upon whether or not the derivative is designated as a hedge. Changes in fair value of a derivative designated as a cash flow hedge are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is recognized in earnings. Changes in the fair value of a derivative instrument designated as a fair value hedge, to the extent the hedge is effective, have no effect on the statement of operations, because changes in fair value of the derivative offsets changes in the fair value of the hedged item. Where hedge accounting is not elected or if a derivative instrument does not qualify as either a fair value hedge or a cash flow hedge, changes in fair value are recognized in earnings. We have elected not to use hedge accounting and as a result, all changes in the fair values of our derivative instruments are recognized in commodity derivative gains in our Consolidated Statements of Operations.

 

 

As of December 31, 2014 and 2013, the fair value of the Company’s derivative agreements was a current asset of approximately $1.3 million and liability of approximately $326,000, respectively. The fair value measurement of the commodity derivative assets and liabilities are measured based upon our valuation model that considers various inputs including (a) quoted forward prices for commodities, (b) time value, (c) notional quantities, (d) current market and contractual prices for the underlying instruments; and (e) the counterparty’s credit risk. Volatility in oil and natural gas prices could have a significant impact on the fair value of our derivative contracts. See Note 10 to the Consolidated Financial Statements for further discussion. The values we report in our financial statements are as of a point in the time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.

 

Due to the volatility of oil and natural gas prices, the estimated fair values of our commodity derivative instruments are subject to large fluctuations from period to period and we expect the volatility to continue. Actual gains or losses recognized related to our commodity derivative instruments will likely differ from those estimated at December 31, 2014 and will depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts.

 

Valuation of Deferred Tax Assets

 

We use the asset and liability method of accounting for income taxes. Under this method, income tax assets and liabilities are determined based on differences between the financial statement carrying values of assets and liabilities and their respective income tax bases (temporary differences). Income tax assets and liabilities are measured using the tax rates expected to be in effect when the temporary differences are likely to reverse. The effect on income tax assets and liabilities of a change in tax rates is included in earnings in the period in which the change is enacted. The book value of income tax assets is limited to the amount of the tax benefit that is more likely than not to be realized in the future.

 

In assessing the need for a valuation allowance on our deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon whether future book income is sufficient to reverse existing temporary differences that give rise to deferred tax assets, as well as whether future taxable income is sufficient to utilize net operating loss and credit carryforwards. Assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both positive and negative. Positive evidence considered by management includes current and forecasted book income over a reasonable period of time. Negative evidence considered by management includes a recent history of book losses which were driven primarily from ceiling test write-downs, which are not fair value based measurements.

 

As of December 31, 2014 and 2013, management assessed the available positive and negative evidence to estimate if sufficient future taxable income would be generated to use the Company’s deferred tax assets and determined that it is not more-likely-than-not that the deferred tax assets would be realized in the near future. Therefore, the Company recorded a full valuation allowance of approximately $13.2 million and $14.9 million on its deferred tax assets as of December 31, 2014 and 2013, respectively.

 

Asset Retirement Obligations

 

We have obligations to remove tangible equipment and restore locations at the end of oil and natural gas production operations. FASB ASC Topic 410, Asset Retirement and Environmental Obligations, requires that the discounted fair value of a liability for an asset retirement obligation (“ARO”) be recognized in the period in which it is incurred with the associated asset retirement cost capitalized as part of the carrying cost of the oil and natural gas asset. Estimating the future restoration and removal costs, or ARO, is difficult and requires management to make estimates and judgments, because most of the obligations are many years in the future, and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations.

 

Inherent in the calculation of the present value of our ARO are numerous assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance. Increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense in the Consolidated Statements of Operations.

 

Non-GAAP Measures

 

Adjusted EBITDA

 

“EBTIDA” 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 and the gain or loss on sold investments or properties. EBITDA and Adjusted EBITDA is consolidated including non-controlling interests and as used and defined by us, may not be comparable to similarly titled measures employed by other companies and are not measures of performance calculated in accordance with GAAP. EBITDA and Adjusted EBITDA should not be considered in isolation or as a substitute for operating income, net income or loss, cash flow provided by or used in operating, investing and financing activities or other income or cash flow statement data prepared in accordance with GAAP. EBITDA and Adjusted EBITDA provide no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. EBITDA and Adjusted EBITDA do not represent funds available for discretionary use because those funds are required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration 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 team for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting and by our lenders pursuant to a covenant under our credit facility.

 

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

 

The following table represents a reconciliation of our net earnings, the most directly comparable GAAP measure, to EBITDA and Adjusted EBITDA for the years ended December 31, 2014 and 2013.

 

		For the Year Ended
		December 31,
(in thousands)		2014				2013
Net income		$	7,235			$	4,268
Adjustments:
Interest expense			471				581
Depreciation, depletion and amortization			2,954				2,922
Income taxes			377				-
EBITDA			11,037				7,771
Adjusted EBITDA
EBITDA			11,037				7,771
Adjustments:
Accretion of asset retirement obligations			117				138
Adjusted EBITDA		$	11,154			$	7,909

 

 

Item 8.    Financial Statements and Supplementary Data.

  

Report of Independent Registered Public Accounting Firm

 

The Board of Directors and Stockholders of Carbon Natural Gas Company

 

We have audited the accompanying consolidated balance sheets of Carbon Natural Gas Company and subsidiaries as of December 31, 2014 and 2013, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Carbon Natural Gas Company and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

 

		/s/ EKS&H LLLP
Denver, Colorado March 31, 2015

 

  

CARBON NATURAL GAS COMPANY

Consolidated Balance Sheets

(In thousands)

 

		December 31,				December 31,
		2014				2013
ASSETS
Current assets:
Cash and cash equivalents		$	1,132			$	243
Accounts receivable:
Revenue			2,287				2,551
Joint interest billings and other			1,038				627
Commodity derivative asset			1,322				-
Prepaid expense, deposits and other current assets			141				95
Total current assets			5,920				3,516
Property and equipment, at cost (note 4)
Oil and gas properties, full cost method of accounting:
Proved, net			30,698				39,033
Unevaluated			2,789				2,235
Other property and equipment, net			304				287
			33,791				41,555
Investments in affiliates (note 5)			1,009				1,002
Other long-term assets			911				688
Total assets		$	41,631			$	46,761
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities		$	7,792			$	6,605
Firm transportation contract obligations (note 12)			487				556
Commodity derivative liability			-				226
Total current liabilities			8,279				7,387
Non-current liabilities:
Commodity derivative liability			-				100
Firm transportation contract obligations (note 12)			852				1,340
Asset retirement obligation (note 2)			2,968				2,699
Notes payable (note 6)			2,100				12,789
Total non-current liabilities			5,920				16,928
Commitments (note 12)
Stockholders’ equity:
Preferred stock, $0.01 par value; authorized 1,000,000 shares, no shares issued and outstanding at December 31, 2014 and 2013			-				-
Common stock, $0.01 par value; authorized 200,000,000 shares, 106,875,447 and 114,470,223 shares issued and outstanding at December 31, 2014 and 2013, respectively			1,069				1,145
Additional paid-in capital			53,160				55,029
Accumulated deficit			(29,832	)			(36,773	)
Total Carbon stockholders’ equity			24,397				19,401
Non-controlling interests			3,035				3,045
Total stockholders’ equity			27,432				22,446
Total liabilities and stockholders’ equity		$	41,631			$	46,761

 

See accompanying notes to Consolidated Financial Statements.

 

 

CARBON NATURAL GAS COMPANY

Consolidated Statements of Operations

(In thousands, except per share amounts)

  

		Twelve months ended December 31,
		2014				2013
Revenue:
Oil and gas		$	22,505			$	18,681
Commodity derivative gain (loss)			1,246				(459	)
Other income			325				416
Total revenue			24,076				18,638
Expenses:
Lease operating expenses			3,333				2,620
Transportation costs			1,808				1,609
Production and property taxes			1,656				1,258
General and administrative			6,133				5,151
Depreciation, depletion and amortization			2,954				2,922
Accretion of asset retirement obligations			117				138
Total expenses			16,001				13,698
Operating income			8,075				4,940
Other income and (expense):
Interest expense			(471	)			(581	)
Equity investment income (loss)			8				(91	)
Total other expense			(463	)			(672	)
Income before income taxes			7,612				4,268
Income tax expense:
Current			377				-
Net income			7,235				4,268
Net (income) loss attributable to non-controlling interests			(294	)			18
Net income attributable to controlling interest		$	6,941			$	4,286
Net income per common share:
Basic		$	0.06			$	0.04
Diluted		$	0.06			$	0.04
Weighted average common shares outstanding (in thousands):
Basic			108,988				112,479
Diluted			114,024				117,096

  

See accompanying notes to Consolidated Financial Statements.

 

 

CARBON NATURAL GAS COMPANY

Consolidated Statements of Stockholders’ Equity

(In thousands)

 

		Common Stock								Additional Paid-in				Non- Controlling				Accumulated				Total Stockholders’
		Shares				Amount				Capital				Interests				Deficit				Equity
Balances, December 31, 2012			115,795			$	1,158			$	54,195			$	3,088			$	(41,059	)		$	17,382
Stock-based compensation											913				-				-				913
Restricted stock activity including amendments, vesting and shares exchanged for tax withholding			(1,325	)			(13	)			(79	)			-				-				(92	)
Non-controlling interest:
Distributions, net			-				-				-				(25	)			-				(25	)
Net income (loss)			-				-				-				(18	)			4,286				4,268
Balances, December 31, 2013			114,470			$	1,145			$	55,029			$	3,045			$	(36,773	)		$	22,446
Purchase of common stock			(8,154	)			(82	)			(3,179	)			-				-				(3,261	)
Stock-based compensation			-				-				1,492				-				-				1,492
Restricted stock activity including vesting and shares exchanged for tax withholding			559				6				(182	)			-				-				(176	)
Non-controlling interests distributions, net			-				-				-				(304	)			-				(304	)
Net income			-				-				-				294				6,941				7,235
Balances, December 31, 2014			106,875			$	1,069			$	53,160			$	3,035			$	(29,832	)		$	27,432

  

See accompanying notes to Consolidated Financial Statements.

 

 

CARBON NATURAL GAS COMPANY

Consolidated Statements of Cash Flows

(In thousands)

  

		Twelve months ended December 31,
		2014				2013
Cash flows from operating activities:
Net income		$	7,235			$	4,268
Items not involving cash:
Depreciation, depletion and amortization			2,954				2,922
Accretion of asset retirement obligations			117				138
Unrealized derivative (gain) loss			(1,648	)			239
Stock-based compensation expense			1,492				913
Equity investment (income) loss			(8	)			91
Net change in:
Accounts receivable			37				857
Prepaid expenses, deposits and other current assets			(46	)			20
Accounts payable, accrued liabilities and firm transportation contracts			1,563				(2,046	)
Due to/from related parties			-				446
Net cash provided by operating activities			11,696				7,848
Cash flows from investing activities:
Development of oil and gas properties and other capital expenditures			(9,001	)			(9,114	)
Acquisition of oil and gas properties			(2,244	)			(501	)
Proceeds from sale of oil and gas properties			15,276				-
Equity method investment			-				125
Other long-term assets			(408	)			(26	)
Net cash provided by (used in) investing activities			3,623				(9,516	)
Cash flows from financing activities:
Purchase of common stock			(3,261	)			-
Vested restricted stock exchanged for tax withholding			(176	)			(92	)
Proceeds from notes payable			5,700				2,700
Payments on notes payable			(16,389	)			(1,000	)
Distribution to non-controlling interests			(304	)			(25	)
Net cash (used in) provided by financing activities			(14,430	)			1,583
Net increase (decrease) in cash and cash equivalents			889				(85	)
Cash and cash equivalents, beginning of period			243				328
Cash and cash equivalents, end of period		$	1,132			$	243

 

See Note 14 – Supplemental Cash Flow Disclosure

 

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 conduct 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

 

Accounting policies used by the Company reflect industry practices and conform to accounting principles generally accepted in the United States of America. The more significant of such accounting policies are briefly discussed below.

 

Principles of Consolidation

 

The Consolidated Financial Statements include the accounts of Carbon and its consolidated subsidiaries. The Company owns 100% of Nytis USA. Nytis USA owns approximately 99% of Nytis LLC. Nytis LLC also holds interests in various oil and gas partnerships.

 

For partnerships where the Company has a controlling interest, the partnerships are consolidated. The Company is currently consolidating 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 interest 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.

 

Cash and Cash Equivalents

 

Cash and cash equivalents in excess of daily requirements have been generally invested in money market accounts, certificates of deposits and other cash equivalents with maturities of three months or less. Such investments are deemed to be cash equivalents for purposes of the Consolidated Financial Statements. The carrying amount of cash equivalents approximates fair value because of the short maturity and high credit quality of these investments.

 

Accounts Receivable

 

The Company’s accounts receivables are primarily comprised of oil and natural gas revenues from producing activities conducted primarily in Illinois, Indiana, Kentucky, Ohio, Tennessee and West Virginia and from other exploration and production companies and individuals who own working interests in the properties that the Company operates. The Company grants credit to all qualified customers, which potentially subjects the Company to credit risk resulting from, among other factors, adverse changes in the industries in which the Company operates and the financial condition of its customers. The Company continuously monitors collections and payments from its customers and maintains an allowance for doubtful accounts based upon its historical experience and any specific customer collection issues that it has identified. At December 31, 2014 and 2013, the Company had not identified any collection issues related to its oil and gas operations and as a consequence no allowance for doubtful accounts was provided for on those dates.

 

 

Note 2 – Summary of Significant Accounting Policies (continued)

 

Oil and Natural Gas Sales

 

The Company principally sells its oil and natural gas production to various purchasers in the industry. The table below presents percentages by purchaser that account for 10% or more of our total oil and natural gas sales for the years ended December 31, 2014 and 2013. There are a number of purchasers in the areas where the Company sells its production. Management does not believe that changing its primary purchasers or a loss of any other single purchaser would materially impact the Company’s business.

 

Purchaser		2014				2013
Purchaser A			29	%			11	%
Purchaser B			20	%			1	%
Purchaser C			13	%			22	%
Purchaser D			11	%			4	%
Purchaser E			7	%			39	%

 

The Company recognizes an asset or a liability, whichever is appropriate, for revenues associated with over-deliveries or under-deliveries of natural gas to purchasers. A purchaser imbalance asset occurs when the Company delivers more natural gas than it nominated to deliver to the purchaser and the purchaser pays only for the nominated amount. Conversely, a purchaser imbalance liability occurs when the Company delivers less natural gas than it nominated to deliver to the purchaser and the purchaser pays for the amount nominated. As of December 31, 2014, the Company has a purchaser imbalance receivable of approximately $182,000 which is recognized as a current asset in the Company’s Consolidated Balance Sheet.

 

Accounting for Oil and Gas Operations

 

The Company uses the full cost method of accounting for oil and gas properties. Accordingly, all costs related 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 gas to oil at the ratio of six thousand cubic feet of natural gas to one barrel of oil. Depletion is calculated using capitalized costs, including estimated asset retirement costs, plus 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. See Note 3 regarding the Company’s 2014 divestitures. 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 or impairment 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 capitalized costs in future periods.

 

For the years ended December 31, 2014 and 2013, the Company did not recognize a ceiling test impairment as the Company’s full cost pool did not exceed the ceiling limitation. Future declines in oil and natural gas prices could result in impairments of our oil and gas properties in future periods.

 

 

Note 2 – Summary of Significant Accounting Policies (continued)

 

Other Property and Equipment

 

Other property and equipment are recorded at cost upon acquisition. Depreciation of other property and equipment over their estimated useful lives is provided for using the straight-line method over three to seven years.

 

Long-Lived Assets

 

The Company reviews its long-lived assets other than oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recovered. The Company looks primarily to the estimated undiscounted future cash flows in its assessment of whether or not long-lived assets have been impaired.

 

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 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 annually to determine if a decline in the fair value of the investment, other than temporary, has occurred. A permanent impairment is recognized if a decline in the fair value occurs. If the Company holds between 20% and 50% of the voting interest in non-consolidated corporate affiliates or greater than a 5% interest of a partnership or limited liability company and exercises significant influence or control, the equity method of accounting is used to account for the investment. The Company’s investment in 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 years ended December 31, 2014 and 2013.

 

		Year Ended December 31,
(in thousands)		2014				2013
Balance at beginning of year		$	2,699			$	2,321
Accretion expense			117				138
Additions during period			152				123
Additions assumed with acquired properties			-				117
Costs incurred			-				-
Balance at end of year		$	2,968			$	2,699

 

 

Note 2 – Summary of Significant Accounting Policies (continued)

 

Financial Instruments

 

The Company’s financial instruments include cash and cash equivalents, accounts receivables, accounts payables, accrued liabilities, derivative instruments and its credit facility. The carrying value of cash and cash equivalents, accounts receivables, payables and accrued liabilities are considered to be representative of their fair value, due to the short maturity of these instruments. The Company’s derivative instruments are recorded at fair value, as discussed below and in Note 10. The carrying amount of the Company’s credit facility approximated fair value since borrowings bear interest at variable rates, which are representative of the Company’s credit adjusted borrowing rate.

 

Commodity Derivative Instruments

 

The Company enters into commodity derivative contracts to manage its exposure to oil and natural gas price volatility with an objective to achieve more predictable cash flows. Commodity derivative contracts may take the form of futures contracts, swaps or options. The Company has elected not to designate its derivatives as cash flow hedges. All derivatives are initially and subsequently measured at estimated fair value and recorded as assets or liabilities on the Consolidated Balance Sheets and the changes in fair value are recognized as gains or losses in revenues in the Consolidated Statements of Operations.

 

Income Taxes

 

Carbon accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases, as well as the future tax consequences attributable to the future utilization of existing tax net operating losses and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

 

The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more likely than not recognition threshold are recognized.

 

Stock - Based Compensation

 

Compensation cost is measured at the grant date, based on the fair value of the awards and is recognized on a straight-line basis over the requisite service period (usually the vesting period).

 

Revenue Recognition

 

The Company accounts for natural gas sales using the entitlements method. The Company accounts for oil sales when title to the product is transferred. Under the entitlements method, revenue is recorded based upon the Company’s share of volumes sold, regardless of whether the Company has taken its proportionate share of volumes produced. The Company records a receivable or payable to the extent it receives less or more than its proportionate share of the related revenue.

 

Earnings Per Common Share

 

Basic earnings per common share is computed by dividing the net income attributable to common stockholders for the period by the weighted average number of common shares outstanding during the period. The shares of restricted common stock granted to certain officers, directors and employees of the Company are included in the computation of basic net income per share only after the shares become fully vested. Diluted earnings per common share includes both the vested and unvested shares of restricted stock and the potential dilution that could occur upon exercise of the 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 the 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)

 

For the years ended December 31, 2014 and 2013, the diluted income per common share calculation excludes the dilutive effect of approximately 2.7 million common stock equivalents that were out-of-the money, respectively and approximately 4.7 million and 3.2 million restricted performance units, respectively, subject to future contingencies.

 

Use of Estimates in the Preparation of Financial Statements

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities and expenses and disclosure of contingent assets and liabilities. Significant items subject to such estimates and assumptions include the carrying value of oil and gas properties, the estimate of proved oil and gas reserve volumes and the related depletion and present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, determining the amounts recorded for deferred income taxes, stock-based compensation, fair value of derivative instruments and asset retirement obligations. Actual results could differ from those estimates and assumptions used.

 

Adopted and Recently Issued Accounting Pronouncements

 

Effective October 1, 2014, the Company early adopted, on a prospective basis, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” This ASU changed the criteria for reporting discontinued operations while enhancing disclosures in this area. There was no impact to the Company’s financial statements or disclosures from the early adoption of this standard.

 

In May 2014, the FASB issued new authoritative accounting guidance related to the recognition of revenue from contracts with customers. This guidance is to be applied using a retrospective method or a modified retrospective method, as outlined in the guidance, and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. Early application is not permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

 

In August 2014, the FASB issued new authoritative guidance that requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the entity’s financial statements are issued, or within one year after the date the entity’s financial statements are available to be issued, and to provide disclosures when certain criteria are met. This guidance is effective for the fiscal years ending after December 15, 2016, and annual and interim periods thereafter. Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures but does not believe it will impact the Company’s financial statements or disclosures.

 

In February 2015, the FASB issued new authoritative accounting guidance meant to clarify the consolidation reporting guidance in GAAP. This guidance is to be applied using a retrospective method or modified retrospective method, as outlined in the guidance, and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015. Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

 

Note 3 – Dispositions and Acquisitions

 

Liberty Participation Agreement

 

On February 25, 2014, Nytis LLC entered into a participation agreement with Liberty Energy LLC (“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 will pay a disproportionate percentage of the costs associated with drilling and completing 20 wells on the covered leases.

 

Following the drilling of these 20 wells, Nytis LLC and Liberty will pay their respective costs on a basis proportionate to their working interests.

 

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

 

As the transaction did not significantly alter the relationship between capitalized costs and proved reserves, the Company did not recognize a gain or loss. The proceeds from the participation agreement were recorded as a reduction of the Company’s investment in its proved and unevaluated oil and gas properties.

 

 

Note 3 – Dispositions and Acquisitions (continued)

  

Acquisitions

 

In May 2013, in two separate transactions, the Company acquired proved producing oil and gas properties and additional interests in partnerships with proved producing properties located in Kentucky and West Virginia for a total purchase price of approximately $517,000.

 

The purchase of these assets qualified as a business combination and, as such, the Company estimated the fair value of the assets acquired and liabilities assumed as of the acquisition date (the date on which the Company obtained control of the properties.) The purchases of these assets were recorded as an investment in the Company’s proved oil and gas properties. There was no significant difference between the fair value of the assets and the purchase price.

 

During 2013, for nominal cash and assumption of nominal partner liabilities, the Company acquired additional partnership interests from other partners.

 

Divestitures

 

On December 15, 2014, Nytis LLC together with Liberty, (the “Sellers”) completed a preliminary closing in accordance with a Purchase and Sale Agreement (the “PSA”) entered into on October 15, 2014, as amended, 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 (the “Leases”).

 

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 closing of this transaction, Nytis LLC received approximately $12.4 million in cash.

 

At the preliminary closing, the buyer provided to Sellers a description of title defects (many of which the parties considered to be readily curable) and estimated that the extent of title defects was less than the twenty percent (20%) threshold provided in the PSA that would have permitted either buyer or Sellers to terminate the transaction.

 

As the transaction did not significantly alter the relationship between capitalized costs and proved reserves, the Company did not recognize a gain or loss. The proceeds from the PSA were recorded as a reduction of the Company’s investment in its proved and unevaluated oil and natural gas properties.

 

 

Note 4 – Property and Equipment

 

Net property and equipment at December 31, 2014 and 2013 consists of the following:

 

		As of December 31,
(in thousands)		2014				2013
Oil and gas properties:
Proved oil and gas properties		$	95,233			$	100,769
Unproved properties not subject to depletion			2,789				2,235
Accumulated depreciation, depletion, amortization and impairment			(64,535	)			(61,736	)
Net oil and gas properties			33,487				41,268
Furniture and fixtures, computer hardware and software, and other equipment			1,131				960
Accumulated depreciation and amortization			(827	)			(673	)
Net other property and equipment			304				287
Total net property and equipment		$	33,791			$	41,555

  

The Company had approximately $2.8 million and $2.2 million, at December 31, 2014 and 2013, respectively, of unproved oil and gas properties not subject to depletion. At December 31, 2014 and 2013, the Company’s unproved properties consist principally of leasehold acquisition costs in the following areas:

 

		As of December 31,
(in thousands)		2014				2013
Illinois Basin:
Indiana		$	433			$	446
Illinois			420				354
Appalachian Basin:
Kentucky			1,142				1,367
Ohio			66				66
West Virginia			728				2
Total unproved properties not subject to depletion		$	2,789			$	2,235

 

During the years ended December 31, 2014 and 2013, expiring leasehold costs reclassified into proved property were approximately $194,000 and $4,000, respectively. 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. These costs do not relate to any individually significant projects. 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 are expected to be completed within five years.

 

The Company capitalized overhead applicable to acquisition, development and exploration activities of approximately $520,000 and $483,000 for the years ended December 31, 2014 and 2013, respectively.

 

Depletion expense related to oil and gas properties for the years ended December 31, 2014 and 2013 was approximately $2.8 million for each year or $0.95 and $0.96 per Mcfe, respectively. Depreciation and amortization expense related to furniture and fixtures, computer hardware and software and other equipment for the years ended December 31, 2014 and 2013 was approximately $154,000 and $133,000, 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 2014 and 2013, the Company recorded equity method income of approximately $8,000 and loss of approximately $91,000, respectively, related to this investment.

 

 

Note 6 – Bank Credit Facility

 

Nytis LLC’s credit facility with Bank of Oklahoma, which matures in May 2017, has a borrowing base of $20.0 million and a maximum line of credit available under hedging arrangements of $9.5 million. 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 that outstanding balances exceed the borrowing base then in effect; however, the Company has the right both to repay principal at any time and to reborrow. Subject to the agreement of 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. Prior to July 2013, for all debt outstanding regardless if the loan was based on the Alternative Base Rate or LIBOR, there was a minimum floor of 4.5% per annum. On June 28, 2013, the Company and Bank of Oklahoma amended the credit agreement whereby the Company’s loans under the credit agreement are no longer subject to the minimum interest rate floor of 4.5% per annum for LIBOR tranches commencing after July 25, 2013 and for loan amounts subject to the Alternate Base Rate after July 31, 2013. 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 December 31, 2014, there were approximately $2.1 million in outstanding borrowings and approximately $17.9 million of additional borrowing capacity available under the credit facility. The Company’s effective borrowing rate at December 31, 2014 was approximately 3.0%. 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 and the payment of dividends, and requires satisfaction of a current ratio (the ratio of current assets (including borrowing base capacity) to current liabilities as defined) of 1.0 to 1.0 and a maximum funded debt ratio (the ratio of the outstanding balance of all interest bearing indebtedness to the sum of EBITDAX (net income plus interest expense, income taxes, depreciation, depletion, amortization, exploration and impairment expenses and other non-cash charges) for the most recently completed fiscal quarter times four) of 4.25 to 1.0 as of the end of any fiscal quarter. 

 

The Company is in compliance with all covenants associated with the credit agreement as of December 31, 2014.

 

Note 7 – Income Taxes

 

The provision for income taxes for the years ended December 31, 2014 and 2013 consists of the following:

 

		Year Ended
(in thousands)		December 31, 2014				December 31, 2013
Current income tax expense		$	377			$	-
Deferred income tax expense			1,624				1,351
Change in valuation allowance			(1,624	)			(1,351	)
Total income tax expense		$	377			$	-

  

  

Note 7 – Income Taxes (continued)

 

The effective income tax rate for the years ended December 31, 2014 and 2013 differed from the statutory U.S. federal income tax rate as follows:

  

		Year Ended
		December 31, 2014				December 31, 2013
Federal income tax rate			35.0	%			35.0	%
State income taxes, net of federal benefit			3.4				3.7
Percentage depletion in excess of basis			(7.2	)			(3.9	)
Non-controlling interest in consolidated partnerships			(1.1	)			(1.3	)
True-up of prior year depletion in excess of basis			(4.2	)			(5.7	)
Rate changes of prior year deferreds			.4				3.9
Increase in valuation allowance and other			(21.3	)			(31.7	)
Total income tax expense			5.0	%			0.0	%

 

The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities at December 31, 2014 and 2013 are presented below:

 

(in thousands)		December 31, 2014				December 31, 2013
Deferred tax assets
Net operating loss carryforwards		$	2,622			$	6,754
Depletion carryforwards			2,347				1,435
Accrual and other			1,242				1,043
Derivatives			(496	)			125
Asset retirement obligations			1,118				1,024
Property, plant and equipment			7,011				5,009
Total deferred tax assets			13,844				15,390
Deferred tax liability
Interest in partnerships			(628	)			(475	)
Less valuation allowance			(13,216	)			(14,915	)
Net deferred tax asset		$	-			$	-

  

The Company has net operating losses (“NOL”) of approximately $6.3 million available to reduce future years’ federal taxable income. The federal net operating losses expire in 2033. The Company has NOL of approximately $10 million available to reduce future years’ state taxable income. These state NOL will expire in the future based upon each jurisdiction’s specific law surrounding NOL carryforwards. Tax returns are subject to audit by various taxation authorities. The results of any audits will be accounted for in the period in which they are determined.

 

The Company believes that the tax positions taken in the Company's tax returns satisfy the more likely than not threshold for benefit recognition. Furthermore, the Company believes it has appropriately addressed material book-tax differences. Carbon is confident that the amounts claimed (or expected to be claimed) in the tax returns reflect the largest amount of such benefits that are greater than fifty percent likely of being realized upon ultimate settlement. Accordingly, no liabilities have been recorded by the Company. Any potential adjustments for uncertain tax positions would be a reclassification between the deferred tax asset related to the Company’s NOL and another deferred tax asset.

 

The Company’s policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company’s income tax provision. As of December 31, 2014, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the current year.

 

  

Note 8 – Stockholders’ Equity

 

Authorized and Issued Capital Stock

 

As of December 31, 2014, the Company had 200,000,000 shares of common stock authorized with a par value of $0.01 per share, of which 106,875,447 were issued and outstanding and 1,000,000 shares of preferred stock with a par value of $0.01 per share, none of which were issued and outstanding. During the year ended December 31, 2014, increases in the Company’s issued and outstanding common stock reflect restricted stock, net of shares exchanged for payroll tax obligation paid by the Company, that vested during the year. In addition, pursuant to a Stock Purchase Agreement dated June 9, 2014, the Company purchased approximately 8.2 million shares of the Company’s common stock from a shareholder for a purchase price of $0.40 per share. The purchase represented 100% of the shareholder’s holding of the Company’s common stock. These shares were cancelled and returned to the Company’s authorized stock and reduced the number of shares issued and outstanding.

 

Equity Plans Prior to Merger

 

In 2011, pursuant to an Agreement and Plan of Merger by and among St. Lawrence Seaway Corporation (“SLSC”), St. Lawrence Merger Sub, Inc. (“Merger Co.”) and Nytis USA, Merger Co. merged with and into Nytis USA with Nytis USA remaining as the surviving subsidiary of SLSC.

 

Pursuant to the merger, all options, warrants and restricted stock were adjusted to reflect the conversion ratio used in the merger. As of December 31, 2014, the Company has 163,076 options outstanding and exercisable, 2,696,133 warrants (including 250,000 warrants granted by SLSC prior to the merger) outstanding and exercisable and 1,468,181 shares of common stock outstanding that are subject to restricted stock agreements.

 

Nytis USA Stock Option Plan

 

The following table reflects the outstanding option awards as of December 31, 2014 and 2013. The awards were made by Nytis USA prior to the merger and were assumed as a result of the merger. The number of shares and the option exercise price have been adjusted in line with the exchange ratio of Nytis USA shares for Carbon shares in the merger.

 

		Number of Shares				Weighted Average Exercise Price				Weighted Average Remaining Contractual Life (Years)
Outstanding – January 1, 2013			163,076			$	0.61				3.00
Outstanding – December 31, 2013			163,076				0.61				2.00
Outstanding – December 31, 2014			163,076				0.61				1.00
Exercisable – December 31, 2014			163,076			$	0.61				1.00

 

Nytis USA Warrants

 

Prior to January 1, 2006, the Company granted 2,446,133 warrants to an officer of the Company. Any shares to be issued upon exercise of the warrants would be from newly issued shares. Utilizing the minimum valuation method under the Black-Scholes option price model, the Company determined that the fair value of the warrants at the date of grant was nil. Each warrant enabled the holder to purchase one share of common stock of the Company, at an initial exercise price of $0.61 per share of common stock until expiry on June 1, 2015. The initial warrant exercise price of $0.61 per share of common stock was to increase annually at 6% starting June 1, 2006 and the exercise price for each of the warrants at December 31, 2010 was $0.85. Pursuant to the merger, the exercise price was fixed at $0.85. Inclusive of 250,000 warrants granted by SLSC prior to the merger with an exercise price of $1.00 which expire on August 31, 2017, the Company has 2,696,133 warrants outstanding at December 31, 2014. The number of warrants have been adjusted in line with the exchange ratio of Nytis USA shares for Carbon shares in the merger.

 

 

Note 8 – Stockholders’ Equity (continued)

 

Nytis USA Restricted Stock Plan

 

Under Nytis USA’s restricted stock plan, participants were granted stock without cost to the participant.

 

As of December 31, 2014, there were 1,468,181 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.

 

On June 25, 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 $335,000 and $168,000 for the years ended December 31, 2014 and 2013, respectively. As of December 31, 2014, there was approximately $671,000 of unrecognized compensation costs related to these restricted stock grants which the Company expects will be recognized ratably over the next 2 years.

 

Carbon Stock Incentive Plan

 

In 2011, the stockholders of Carbon approved the adoption of Carbon’s 2011 Stock Incentive Plan (“Carbon Plan”), under which 12,600,000 shares of common stock were authorized for issuance to Carbon officers, directors, employees or consultants eligible to receive awards under the Carbon Plan.

 

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

 

Restricted Stock

 

Restricted stock awards for employees vest ratably over a three-year service period and 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). For restricted stock granted in 2014, the Company recognized compensation expense based on the grant date fair value of the shares, utilizing an enterprise value approach, using valuation metrics primarily based on multiples of cash flow from operations, production and reserves. For restricted stock and performance units granted in 2013, the Company utilized the closing price of the Company’s stock on the date of grant to recognize compensation expense. The following table shows a summary of the Company’s unvested restricted stock under the Carbon Plan as of December 31, 2014 and 2013 as well as activity during the years then ended.

 

						Weighted Avg
		Number				Grant Date
		of Shares				Fair Value
Restricted stock awards, nonvested, January 1, 2013			1,610,000			$	0.62
Granted			1,600,000				0.64
Vested			(429,997	)			0.62
Restricted stock awards, nonvested, December 31, 2013			2,780,003				0.63
Granted			1,600,000				0.59
Vested			(856,662	)			0.63
Restricted stock awards, nonvested, December 31, 2014			3,523,341			$	0.61

 

Compensation costs recognized for these restricted stock grants were approximately $811,000 and $526,000 for the years ended December 31, 2014 and 2013, respectively. As of December 31, 2014, there was approximately $1.3 million of unrecognized compensation costs related to these restricted stock grants which the Company expects to be recognized over the next 6.3 years.

 

 

Note 8 – Stockholders’ Equity (continued)

 

Restricted Performance Units

 

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 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. The following table shows a summary of the Company’s unvested performance units as of December 31, 2014 and 2013 as well as activity during the years then ended.

 

		Number
		of Shares
Restricted performance units, non-vested, January 1, 2013			1,166,160
Granted			1,920,000
Restricted performance units, non-vested, December 31, 2013			3,086,160
Granted			1,600,000
Restricted performance units, non-vested, December 31, 2014			4,686,160

 

The Company accounts for the performance units granted during 2012 and 2014 at their fair value determined at the date of grant, which were $.64 and $.59 per share, respectively. The final measurement of compensation cost will be based on the number of performance units that ultimately vest. At December 31, 2014, the Company estimated that none of the performance units granted in 2012 and 2014 would vest due to change in control and other performance provisions and accordingly, no compensation cost has been recorded. As of December 31, 2014, if change in control and other performance provisions pursuant to the terms and conditions of these agreements are met in full, the estimated unrecognized compensation cost related to the performance units granted in 2012 and 2014 would be approximately $2.2 million.

 

The performance units granted in 2013 contain specific vesting provisions, no change in control provisions nor any performance conditions other than stock price performance. Due to different earning requirements compared to the performance units granted in 2012 and 2014, 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. MCS is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility was calculated based on the historical volatility of the Company’s common stock and those of the Company’s defined peer group, which was determined to be 92.92%. A risk free interest rate of .39% was determined based on the yield of U.S. Treasury strips with maturities similar to those of the expected term of the performance units which was determined to be 2.87 years. The grant date fair value of these performance units as determined by the valuation model was $.54 per share. Compensation costs recognized for these performance units were approximately $346,000 and $218,000 for the years ended December 31, 2014 and 2013, respectively. As of December 31, 2014, there was approximately $473,000 of unrecognized compensation costs related to the performance units granted in 2013. These costs are expected to be recognized over the next 1.3 years.

 

  

Note 9 – Accounts Payable and Accrued Liabilities

 

Accounts payable and accrued liabilities at December 31, 2014 and 2013 consist of the following:

 

		As of December 31,
(in thousands)		2014				2013
Accounts payable		$	742			$	2,151
Oil and gas revenue payable to oil and gas property owners			1,296				1,307
Production taxes payable			132				165
Drilling advances received from joint venture partner			2,354				740
Accrued drilling costs			166				162
Accrued lease operating costs			74				42
Accrued ad valorem taxes			1,194				681
Accrued general and administrative expenses			1,247				1,146
Accrued income taxes payable			377				-
Other liabilities			210				211
Total accounts payable and accrued liabilities		$	7,792			$	6,605

 

Note 10 – Fair Value Measurements

 

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

 

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

 

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

 

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

 

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s policy is to recognize transfers in and/or out of fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. 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 December 31, 2014 and 2013 by level within the fair value hierarchy:

 

		Fair Value Measurements Using
(in thousands)		Level 1				Level 2				Level 3				Total
December 31, 2014
Assets:
Commodity derivatives		$	-			$	1,322			$	-			$	1,322
December 31, 2013
Liabilities:
Commodity derivatives		$	-			$	326			$	-			$	326

 

 

Note 10 – Fair Value Measurements (continued)

 

As of December 31, 2014, the Company’s commodity derivative financial instruments are comprised of seven natural gas swap agreements and two oil swap agreements. As of December 31, 2013, the Company’s commodity derivative financial instruments were comprised of nine natural gas swap agreements and five oil swap agreements. The fair values of the swap agreements are determined under the income valuation technique using a discounted cash flow model. The valuation model requires a variety of inputs, including contractual terms, published forward prices, volatilities for options and discount rates, as appropriate. The Company’s estimates of fair value of derivatives include consideration of the counterparty’s credit worthiness, the Company’s credit worthiness and the time value of money. The consideration of these factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view. All of the significant inputs are observable, either directly or indirectly; therefore, the Company’s derivative instruments are included within the Level 2 fair value hierarchy. The counterparty in all of the Company’s commodity derivative financial instruments is the lender in the Company’s bank credit facility.

 

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

 

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

 

The 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 years ended December 31, 2014 and 2013, the Company recorded asset retirement obligations for additions of approximately $152,000 and $240,000, respectively. See Note 2 for additional information.

 

To determine the fair value of the proved developed properties acquired, the Company used a discounted cash flow model based on an income approach and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. The Company determined the appropriate discount rates used for the discounted cash flow analyses by first determining the Company’s weighted average cost of capital plus property specific risk premiums for the assets acquired. The proved developed properties acquired have a much longer reserve to production ratio than its peer group and extreme sensitivities to changes in natural gas prices relative to the resultant present value of the proved developed properties. The Company estimated property specific risk premiums taking those factors, among others, into consideration.

 

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

 

The Company assumed certain firm transportation contracts as part of an acquisition in 2011. The fair value of the 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 11 – Physical Delivery Contracts and Commodity Derivatives

 

The Company has historically used commodity-based derivative contracts to manage exposures to commodity price on certain of its oil and natural gas production. The Company does not hold or issue derivative financial instruments for speculative or trading purposes. The Company also enters into gas physical delivery contracts to effectively provide gas price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded at fair value in the Consolidated Financial Statements.

 

At December 31, 2014, the Company has a fixed price contract requiring physical deliveries for approximately 530 Bbl/month at an average sales price of $96.75 per Bbl from January 2015 through August 2015. The Company’s other oil and gas sales contracts approximate index prices.

 

 

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

 

The Company’s swap agreements as of December 31, 2014 are summarized in the table below:

 

		Natural Gas								Oil
						Weighted								Weighted
						Average								Average
Period		MMBtu				Price (a)				Bbl				Price (b)
Jan - Mar 2015			220,000			$	4.06				5,000			$	94.52
Apr - Jun 2015			170,000			$	4.04				3,000			$	94.80
Jul - Sep 2015			180,000			$	4.05				2,000			$	94.80
Oct - Dec 2015			180,000			$	4.05				-				-
Jan - Mar 2016			30,000			$	4.20				-				-
Apr 2016			10,000			$	4.20				-				-

  

(a)	NYMEX Henry Hub Natural Gas futures contract for the respective delivery month.
(b)	NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective delivery month.

 

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

 

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

  

(in thousands)		As of December 31,
		2014				2013
Commodity derivative contracts:
Current assets		$	1,322			$	-
Current liabilities		$	-			$	226
Non-current liabilities		$	-			$	100

 

The table below summarizes the realized and unrealized gains and losses related to the Company’s derivative instruments for the years ended December 31, 2014 and 2013. These realized and unrealized gains and losses are recorded and included in commodity derivative (loss) gain in the accompanying Consolidated Statements of Operations.

 

(in thousands)		For the year ended December 31,
		2014				2013
Commodity derivative contracts:
Realized (losses)		$	(402	)		$	(220	)
Unrealized gains (losses)			1,648				(239	)
Total realized and unrealized gains (losses), net		$	1,246			$	(459	)

 

Realized 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 Sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the Consolidated Balance Sheets:

 

												Net
				Gross								Recognized
				Recognized				Gross				Fair Value
				Assets/				Amounts				Assets/
		Balance Sheet Classification		Liabilities				Offset				Liabilities
Commodity derivative assets:		Current derivative asset		$	1,322			$	-			$	1,322
Total derivative assets				$	1,322			$	-			$	1,322

 

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

 

Note 12 – Commitments

 

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

 

The Company has entered into long-term firm transportation contracts to ensure the transport for certain of its gas production to purchasers. Firm transportation volumes and the related demand charges for the remaining term of these contracts at December 31, 2014 are summarized in the table below.

 

Period		Dekatherms per day				Demand Charges
Jan 2015 - May 2015			5,950			$0.20 - $0.67
Jun 2015 - Oct 2015			4,800			$0.22 - $0.67
Nov 2015 - Dec 2017			3,300			$0.22 - $0.67
Jan 2018 - May 2036			1,000			$0.22

 

A liability of approximately $1.3 million related to firm transportation contracts assumed in a 2011 asset acquisition, which represents the remaining commitment, is reflected on the Company’s Consolidated Balance Sheets as of December 31, 2014. 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.

 

The Company leases approximately 5,500 square feet of administrative office space in Denver, Colorado under an operating lease arrangement expiring in 2016 and approximately 5,300 square feet of office space in Lexington, Kentucky. For the years ended December 31, 2014 and 2013, the Company incurred rental expenses of $207,000 and $189,000, respectively. The Company has minimum lease payments for its office space and equipment of approximately $238,000 and $171,000 for 2015 and 2016, respectively.

 

Note 13 – Retirement Savings Plan

 

The Company outsources certain payroll and human resource functions to an administrative company. In conjunction with this arrangement, the Company has a 401(k) plan available to eligible employees. The plan provides for 6% matching which vests immediately. For the years ended December 31, 2014 and 2013, the Company paid approximately $249,000 and $192,000, respectively, for 401(k) contributions and related administrative expenses.

 

 

Note 14 – Supplemental Cash Flow Disclosure

 

Supplemental cash flow disclosures for the years ended December 31, 2014 and 2013 are presented below:

 

(in thousands)		For the Year Ended December 31,
		2014				2013
Cash paid for interest payments		$	482			$	548
Non-cash transactions:
Increase (decrease) in net asset retirement obligations		$	152			$	240
(Decrease) increase in accounts payable and accrued liabilities included in oil and gas properties		$	(932	)		$	1,046
Receivables due from partners assumed in acquisitions		$	2			$	20

 

Note 15 – Subsequent Events

 

On December 15, 2014, Nytis LLC together with Liberty, (the “Sellers”) completed a preliminary closing in accordance with a Purchase and Sale Agreement (the “PSA”) entered into on October 15, 2014, as amended, 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 (the “Leases”).

 

At the preliminary closing, the buyer provided to Sellers a description of title defects (many of which the parties considered to be readily curable) and estimated that the extent of title defects was less than the twenty percent (20%) threshold provided in the PSA that would have permitted either buyer or Sellers to terminate the transaction.

 

A final closing is scheduled for mid-April 2015 at which time the Sellers’ curative work and substitute acreage will be agreed to and may result in a downward revision of the purchase price.

 

 

Note 16 – Supplemental Financial Data – Oil and Gas Producing Activities (unaudited)

 

Estimated Proved Oil and Gas Reserves

 

The reserve estimates as of December 31, 2014 and 2013 presented herein were made in accordance with oil and gas reserve estimation and disclosure authoritative accounting guidance.

 

Proved oil and gas reserves as of December 31, 2014 and 2013 were calculated based on the prices for oil and gas during the twelve month period before the reporting date, determined as an un-weighted arithmetic average of the first-day-of-the month price for each month within such period. This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. SEC rules dictate the types of technologies that a company may use to establish reserve estimates, including the extraction of non-traditional resources, such as bitumen extracted from oil sands as well as oil and gas extracted from shales.

 

The Company’s estimates of its net proved, net proved developed, and net proved undeveloped oil and gas reserves and changes in its net proved oil and gas reserves for 2014 and 2013 are presented in the table below. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Existing economic conditions include the average prices for oil and gas during the twelve month period prior to the reporting date of December 31, 2014 and 2013 unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Prices do not include the effects of commodity derivatives. The independent petroleum engineering firm, Cawley, Gillespie & Associates, Inc. (“CGA”), evaluated and prepared independent estimated proved reserves quantities and related pre-tax future cash flows as of December 31, 2014 and 2013. To facilitate the preparation of an independent reserve study, we provided CGA our reserve database and related supporting technical, economic, production and ownership information. Estimated reserves and related pre-tax future cash flows for the non-controlling interests of the consolidated partnerships included in the Company’s Consolidated Financial Statements, were based on CGA’s estimated reserves and related pre-tax future cash flows for the specific properties in the partnerships and have been added to CGA’s reserve estimates for December 31, 2014 and 2013. See Note 2 for additional information.

 

Proved developed oil and gas reserves are proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

 

Proved undeveloped oil and gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

 

Note 16 – Supplemental Financial Data – Oil and Gas Producing Activities (unaudited) (continued)

 

A summary of the Company’s changes in quantities of proved oil and gas reserves for the years ended December 31, 2014 and 2013 are as follows:

 

		2014												2013
		Oil				Natural Gas				Total				Oil				Natural Gas				Total
		MBbls				MMcf				MMcfe				MBbls				MMcf				MMcfe
Proved reserves, beginning of year			822				36,684				41,616				872				33,646				38,878
Revisions of previous estimates			(40	)			2,358				2,118				(249	)			3,459				1,965
Extensions and discoveries			205				44				1,274				305				1,394				3,224
Production			(134	)			(2,138	)			(2,942	)			(107	)			(2,252	)			(2,894	)
Purchases of reserves in-place			-				-				-				1				437				443
Sales of reserves in-place			-				-				-				-				-				-
Proved reserves, end of year			853				36,948				42,066				822				36,684				41,616
Proved developed reserves at:
End of Year			770				35,935				40,555				748				35,317				39,805
Proved undeveloped reserves at:
End of Year			83				1,013				1,511				74				1,367				1,811

 

The estimated proved reserves for December 31, 2014 and 2013 includes 3.3 Bcfe in each year attributed to non-controlling interests of consolidated partnerships.

 

In 2013 revisions of previous oil estimates consisted of a decrease of approximately 109 MBbls associated with performance declines and a decrease of approximately 161 MBbls associated with proved undeveloped locations that were determined not to be viable. Revisions in 2014 and 2013 of previous estimates for natural gas are principally attributed to the increase in natural gas prices which extended the economic life of the wells.

 

Aggregate Capitalized Costs

 

The aggregate capitalized costs relating to oil and gas producing activities at the end of each of the years indicated were as follows:

 

		2014				2013
		(in thousands)
Oil and gas properties
Proved oil and gas properties		$	95,233			$	100,769
Unproved properties not subject to depletion			2,789				2,235
Accumulated depreciation, depletion, amortization and impairment			(64,535	)			(61,736	)
Net oil and gas properties		$	33,487			$	41,268

  

 

Note 16 – Supplemental Financial Data – Oil and Gas Producing Activities (unaudited) (continued)

 

Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities

 

The following costs were incurred in oil and gas property acquisition, exploration, and development activities during the years ended December 31, 2014 and 2013:

 

		2014				2013
		(in thousands)
Property acquisition costs:
Unevaluated properties		$	2,165			$	1,117
Proved properties and gathering facilities			78				501
Development costs			8,685				7,818
Gathering facilities			144				1
Asset retirement obligation			152				240
Total costs incurred		$	11,224			$	9,677

  

The Company’s investment in unproved properties as of December 31, 2014, by the year in which such costs were incurred is set forth in the table below:

 

		2014				2013				2012 and Prior
		(in thousands)
Acquisition costs		$	1,762			$	832			$	195

 

Results of Operations from Oil and Gas Producing Activities

 

Results of operations from oil and gas producing activities for the years ended December 31, 2014 and 2013 are presented below:

 

		2014				2013
		(in thousands)
Oil and gas sales, including commodity derivative gains		$	23,789			$	18,222
Expenses:
Production expenses			6,797				5,487
Depletion expense			2,800				2,789
Accretion of asset retirement obligations			117				138
Total expenses			9,714				8,414
Results of operations from oil and gas producing activities		$	14,075			$	9,808
Depletion rate per Mcfe		$	0.95			$	0.96

 

Standardized Measure of Discounted Future Net Cash Flows

 

Future oil and gas sales are calculated applying the prices used in estimating the Company’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes were considered only to the extent provided by contractual arrangements in existence at each year-end. Future production and development costs, which include costs related to plugging of wells, removal of facilities and equipment, and site restoration, are calculated by estimating the expenditures to be incurred in producing and developing the proved oil and gas reserves at the end of each year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the estimated future pretax net cash flows relating to proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses give effect to tax deductions, credits, and allowances relating to the proved oil and gas reserves. All cash flow amounts, including income taxes, are discounted at 10%.

 

 

Note 16 – Supplemental Financial Data – Oil and Gas Producing Activities (unaudited) (continued)

 

Changes in the demand for oil and natural gas, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of the Company’s proved reserves. Management does not rely upon the information that follows in making investment decisions.

 

		December 31,
		2014				2013
		(in thousands)
Future cash inflows		$	250,659			$	218,545
Future production costs			(96,035	)			(91,013	)
Future development costs			(3,908	)			(4,152	)
Future income taxes			(32,234	)			(13,920	)
Future net cash flows			118,482				109,460
10% annual discount			(53,476	)			(53,018	)
Standardized measure of discounted future net cash flows		$	65,006			$	56,442

 

Changes in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

 

An analysis of the changes in the standardized measure of discounted future net cash flows during each of the last two years is as follows:

 

		December 31,
		2014				2013
		(in thousands)
Standardized measure of discounted future net cash flows, beginning of year		$	56,442			$	45,592
Sales of oil and gas, net of production costs and taxes			(15,746	)			(13,194	)
Price revisions			10,220				2,852
Extensions, discoveries and improved recovery, less related costs			6,561				10,869
Changes in estimated future development costs			959				980
Development costs incurred during the period			1,010				782
Quantity revisions			3,490				2,513
Accretion of discount			5,644				4,559
Net changes in future income taxes			(2,010	)			-
Purchases of reserves-in-place			-				293
Sales of reserves-in-place			-				-
Changes in production rates timing and other			(1,564	)			1,196
Standardized measure of discounted future net cash flows, end of year		$	65,006			$	56,442

 

The twelve month weighted averaged adjusted prices in effect at December 31, 2014 and 2013 were as follows:

 

		2014				2013
Oil (per Bbl)		$	92.10			$	94.08
Natural Gas (per Mcf)		$	4.64			$	3.84

 

 

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

None.

 

Item 9A.    Controls and Procedures.

 

Evaluation of Disclosure Controls and Procedures.

 

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

 

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

 

Changes in Internal Control Over Financial Reporting.

 

There has not been any change in our internal control over financial reporting that occurred during the quarter ended December 31, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

Management's Annual Report on Internal Control Over Financial Reporting

 

The Company’s management is responsible for establishing internal control over financial reporting as defined in Rules 13a-15(f) and 15(d)-15(f) under the Securities Exchange Act of 1934.

 

The Company’s internal controls over financial reporting are intended to be designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. The Company’s internal controls over financial reporting are expected to include those policies and procedures that management believes are necessary that:

  

	(i)	pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
	(ii)	provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

 

(iii)

provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

  

As of December 31, 2014, management assessed the effectiveness of the Company's internal control over financial reporting based on the criteria set forth in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, our management believes that, as of December 31, 2014, our internal control over financial reporting was effective based on these criteria.

 

This Annual Report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting due to the permanent exemption from such requirement for smaller reporting companies.

 

A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the internal control system are met. Because of the inherent limitations of any internal control system, no evaluation of controls can provide assurance that all control issues, if any, within a company have been detected.

 

 

Item 9B.    Other Information.

 

None.

 

PART III

 

Item 10.    Directors, Executive Officers and Corporate Governance.

 

The following persons serve as executive officers and directors of Carbon.

 

Name		Age		Position
Patrick R. McDonald		58		Chief Executive Officer, Director
Mark D. Pierce		61		President
Kevin D. Struzeski		56		Chief Financial Officer, Treasurer and Secretary
James H. Brandi		66		Chairman of the Board
David H. Kennedy		65		Director
Bryan H. Lawrence		72		Director
Peter A. Leidel		58		Director
Edwin H. Morgens		73		Director

  

Executive Officer/Director

 

Patrick R. McDonald. Mr. McDonald is Chief Executive Officer of the Company and has been Chief Executive Officer, President and Director of Nytis USA since 2004. From 1998 to 2003, Mr. McDonald was Chief Executive Officer, President and Director of Carbon Energy Corporation, an oil and gas exploration and production company which in 2003 was merged with Evergreen Resources, Inc. From 1987 to 1997 Mr. McDonald was Chief Executive Officer, President and Director of Interenergy Corporation, a natural gas gathering, processing and marketing company which in December 1997 was merged with KN Energy Inc. Prior to that he worked as an exploration geologist with Texaco International Exploration Company where he was responsible for oil and gas exploration efforts in the Middle East and Far East. Mr. McDonald served as Chief Executive Officer of Forest Oil Corporation (“Forest”) until the completion of its business combination with Sabine Oil & Gas (OTC: SOGC) in December 2014 for which he received separate compensation and benefits from Forest. Mr. McDonald continues to serve as a director of Sabine Oil & Gas. Mr. McDonald received a Bachelor’s degree in Geology and Economics from Ohio Wesleyan University and a Masters degree in Business Administration Finance from New York University. Mr. McDonald is a Certified Petroleum Geologist and is a member of the American Association of the Petroleum Geologists and of the Canadian Society of Petroleum Geologists.

 

Our Board of Directors believes that Mr. McDonald, as our Chief Executive Officer and as the founder of Nytis USA, should serve as a director because of his unique understanding of the opportunities and challenges that we face and his in-depth knowledge about the oil and natural gas business, and our long-term growth strategies.

 

Other Directors

 

The following information pertains to our non-employee directors, their principal occupations and other public company directorships for at least the last five years and information regarding their specific experiences, qualifications, attributes and skills.

 

James H. Brandi. Mr. Brandi has been a Director of the Company since March 2012 and Chairman of the Board since October 2012. Mr. Brandi retired from a position as Managing Director of BNP Paribas Securities Corp., an investment banking firm, where he served from 2010 until late 2011. From 2005 to 2010, Mr. Brandi was a partner of Hill Street Capital, LLC, a financial advisory and private investment firm which was purchased by BNP Paribas in 2010. From 2001 to 2005, Mr. Brandi was a Managing Director at UBS Securities, LLC, where he was the Deputy Global Head of the Energy and Power Groups. Prior to 2001, Mr. Brandi was a Managing Director at Dillon, Read & Co. Inc. and later its successor firm, UBS Warburg, concentrating on transactions in the energy and consumer goods areas. Mr. Brandi currently serves as a director of Approach Resources Inc. (NASDAQ:AREX) and OGE Energy Corp. (NYSE:OGE). Mr. Brandi is a trustee of The Kenyon Review and a former trustee of Kenyon College.

 

 

Our Board of Directors believes that Mr. Brandi should serve as director and our Chairman because of his experience on the board of directors of other public companies, which our Board believes will be beneficial to us as we move forward as a public company. He also has extensive financial expertise from his education background (Harvard MBA) and his 35 year career in investment banking. His background will be important in his role as Chairman of the Audit Committee and its oversight responsibility regarding the quality and integrity of our accounting and financial reporting process and the auditing of our financial statements.

 

David H. Kennedy. Mr. Kennedy has been a Director of the Company since December 2014 and previously served as a director of the Company. Mr. Kennedy has served as Executive Advisor to Cadent Energy Partners since 2005 and he is a director and chairman of the Audit Committee of Logan International Inc. (Toronto Stock Exchange: LII). From 2001 – 2004, Mr. Kennedy served as an advisor to RBC Energy Fund and served on the boards of several of its portfolio companies. From 1999 to 2004, Mr. Kennedy was a director of Carbon Energy Corporation before its sale to Evergreen Resources in 2004. From 1996 to 2006, Mr. Kennedy was a director and chairman of the Audit Committee of Maverick Tube Corporation, which was sold to Tenaris SA in 2006. He was a managing director of First Reserve Corporation from its founding in 1981 until 1998, serving on numerous boards of its portfolio companies. From 1974 to 1981, Mr. Kennedy was with Price Waterhouse in San Francisco and New York in audit and tax services before leaving to join First Reserve.

 

Our Board of Directors believes that Mr. Kennedy should serve as director because of his current and prior experience as a director of the Company together with his experience on the board of directors of other public companies. His energy industry knowledge and financial expertise will contribute to the Board of Directors oversight responsibility regarding the quality and integrity of our accounting and financial reporting process and the auditing of our financial statements.

 

Bryan H. Lawrence. Mr. Lawrence has been a Director of the Company since February 2011 and of Nytis USA since 2005. Mr. Lawrence is a founder and member of Yorktown Partners LLC which was established in September 1990. Yorktown Partners LLC is the manager of private equity partnerships that invest in the energy industry. Mr. Lawrence had been employed at Dillon, Read & Co. Inc. since 1966, serving as a Managing Director until the merger of Dillon Read with SBC Warburg in September 1997. Mr. Lawrence also serves as a Director of Crosstex Energy, Inc. (NASDAQ:XTEX), Star Gas Partners, L.P. (NYSE:SGU), Approach Resources, Inc. (NASDAQ: AREX) and certain non-public companies in the energy industry in which the Yorktown partnerships hold equity interests. Mr. Lawrence served as a director of Carbon Energy Corporation and Interenergy Corporation.

 

Our Board of Directors believes that Mr. Lawrence should serve as a director because of his experience on the Board of Directors of other public companies, which our Board of Directors believes will be beneficial to us as we move forward as a public company, as well as Mr. Lawrence’s relevant business experience in the energy industry and his extensive financial expertise, which he has acquired through his years of experience in the investment banking industry.

 

Peter A. Leidel. Mr. Leidel has been a Director of the Company since February 2011 and of Nytis USA since 2005. Mr. Leidel is a founder and member of Yorktown Partners LLC which was established in September 1990. Yorktown Partners LLC is the manager of private equity partnerships that invest in the energy industry. Previously, he was a Senior Vice President of Dillon, Read & Co. Inc. He was previously employed in corporate treasury positions at Mobil Corporation and worked for KPMG Peat Marwick and the U.S. Patent and Trademark Office. Mr. Leidel is a director of Mid-Con Energy Partners, L.P. (NASDAQ:MCEP) and certain non-public companies in the energy industry in which the Yorktown partnerships hold equity interests. Mr. Leidel served as a director of Carbon Energy Corporation and Interenergy Corporation. He was a Certified Public Accountant.

 

Our Board of Directors believes that Mr. Leidel should serve as a director because of his significant knowledge of our industry, his prior experience with our business and his financial expertise, which will be important as our Board of Directors exercises its oversight responsibility regarding the quality and integrity of our accounting and financial reporting processes and the auditing of our financial statements.

 

Edwin H. Morgens. Mr. Morgens has been a Director of the Company since May 2012. Mr. Morgens is Chairman and Co-founder of Morgens, Waterall, Vintiadis & Company, Inc., a New York City investment firm that he founded in 1967. He is a former director of Wayside Technology Group, Inc., TransMontaigne, Inc., Sheffield Exploration, and Scientific American Magazine Inc. He is currently a trustee of the American Museum of Natural History and emeritus trustee of Cornell University.

 

Our Board of Directors believes that Mr. Morgens should serve as director because of his current and prior experience on the Board of Directors of other public companies and his extensive financial expertise, which he has acquired through his years of experience in the financial investment advisory industry.

 

 

Other Executive Officers

 

Mark D. Pierce. Mr. Pierce has been President of the Company since October 2012 and was the general manager and Senior Vice President for Nytis LLC from 2009 to 2012. From 2005 until 2009, he was Operations Manager for Nytis LLC. He began his career at Texaco, Inc. in 1975 and worked for 20 years with Ashland Exploration, Inc. (“Ashland”). At Ashland, he spent 12 years in the production/reservoir engineering area and then moved into the executive level with oversight at various times of marketing, finance, business development, external affairs, operations and land. His experience includes both domestic and international work. He is a registered Petroleum Engineer in Kentucky, West Virginia and Ohio.

 

Kevin D. Struzeski.  Mr. Struzeski was appointed the Company’s Chief Financial Officer, Treasurer and Secretary on February 14, 2011 and has been the CFO, Treasurer and Secretary of Nytis USA since 2005.  From 2003 to 2004, Mr. Struzeski was a Director of Treasury of Evergreen Resources, Inc., and from 1998 to 2003, he was Chief Financial Officer, Secretary and Treasurer of Carbon Energy Corporation. Mr. Struzeski was also Chief Financial Officer, Secretary and Treasurer of Carbon Energy Canada Corporation. Mr. Struzeski served as Accounting Manager for Media One Group from 1997 to 1998 and prior to that was employed as Controller for Interenergy Corporation from 1995 to 1997. Mr. Struzeski is a Certified Public Accountant.

 

Terms of Office

 

Our Board of Directors currently consists of six directors, each of whom is elected annually either at an annual meeting of our stockholders or through the affirmative vote of the holders of a majority of the Company’s voting stock. Each director will continue to serve as a director until such director’s successor is duly elected and qualified or until their earlier resignation, removal or death.

 

Family Relationships

 

There are no family relationships between or among any of the current directors or executive officers.

 

Involvement in Certain Legal Proceedings

 

During the past ten years, none of the persons serving as executive officers or directors of the Company have been the subject matter of any of the following legal proceedings that are required to be disclosed pursuant to Item 401(f) of Regulation S-K including: (a) any bankruptcy petition filed by or against any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time; (b) any criminal convictions; (c) any order, judgment, or decree permanently or temporarily enjoining, barring, suspending or otherwise limiting his involvement in any type of business, securities or banking activities; (d) any finding by a court, the SEC or the CFTC to have violated a federal or state securities or commodities law, any law or regulation respecting financial institutions or insurance companies, or any law or regulation prohibiting mail or wire fraud; or (e) any sanction or order of any self-regulatory organization or registered entity or equivalent exchange, association or entity. Further, no such legal proceedings are believed to be contemplated by governmental authorities against any director or executive officer.

 

Section 16(a) Beneficial Ownership Reporting Compliance:

 

Section 16(a) of the 1934 Act requires the Company’s directors and officers and any persons who own more than ten percent of the Company’s equity securities, to file reports of ownership and changes in ownership with the Securities and Exchange Commission (the “SEC”). All directors, officers and greater than ten-percent stockholders are required by SEC regulation to furnish the Company with copies of all Section 16(a) reports files. Based solely on our review of the copies of Forms 3, 4 and 5, and any amendments thereto furnished to us during the fiscal year ended December 31, 2014, we believe that during the Company’s 2014 fiscal year all filing requirements applicable to our officers, directors and greater-than-ten-percent stockholders were complied with.

 

Code of Ethics

 

The Board of Directors has adopted a Code of Ethics, as defined under the federal securities laws that applies to all directors and officers of the Company. A copy of the Code of Ethics has been filed with the SEC as Exhibit 14 to the Company’s Annual Report on Form 10-K for 2004.

 

Board Committees

 

The Board has a standing Audit Committee and a Compensation, Nominating and Governance Committee. The Board has adopted a formal written charter for each of these committees that is available on our website at www.carbonnaturalgas.com.

 

The table below provides the current composition of each standing committee of our Board:

 

				Compensation/
				Nominating/
Name		Audit		Governance
James H. Brandi		X		X
David H. Kennedy		X		X
Peter A. Leidel		X		X
Edwin H. Morgens		X		X

 

 

The Audit Committee’s primary duties and responsibilities are to assist the Board in monitoring the integrity of our financial statements, the independent registered public accounting firm’s qualifications, performance and independence, management’s effectiveness of internal controls and our compliance with legal and regulatory requirements. The Audit Committee is directly responsible for the appointment, retention, compensation, evaluation and termination of our independent registered public accounting firm and has the sole authority to approve all audit and permitted non-audit engagement fees and terms. The Audit Committee is presently comprised of Messrs. Brandi (Chairmen), Kennedy, Leidel and Morgens of which Messrs. Brandi, Kennedy and Morgens are independent directors under Nasdaq listing rules. The Board has determined that Mr. Brandi qualifies as an “audit committee financial expert” as defined by Securities and Exchange Commission rules.

 

The Audit Committee was formed in September 2012 and held five meetings during 2014. Prior to the formation of the Audit Committee, the entire Board as a whole acted as the Company’s Audit Committee.

 

The Compensation, Nominating and Governance Committee discharges the responsibilities of the Board with respect to our compensation programs and compensation of our executives and directors. The Compensation, Nominating and Governance Committee has overall responsibility for determining the compensation of our executive officers and reviewing director compensation. The Compensation, Nominating and Governance Committee is also charged with the administration of our 2011 Stock Incentive Plan. The Compensation Committee is presently comprised of Messrs. Morgens (Chairman), Brandi, Kennedy and Leidel, each of whom is an outside director for purposes of Section 162(m) of the Internal Revenue Code and a non-employee director for purposes of Rule 16b-3 under the Exchange Act.

 

The other functions of the Compensation, Nominating and Governance Committee is to identify individuals qualified to become directors and recommend to the Board nominees for all directorships, identify directors qualified to serve on Board committees and recommend to the Board members for each committee, develop and recommend to the Board a set of corporate governance guidelines and otherwise take a leadership role in shaping our corporate governance.

 

In identifying and evaluating nominees for directors, the Compensation, Nominating and Governance Committee seeks to ensure that the Board possesses, in the aggregate, the strategic, managerial and financial skills and experience necessary to fulfill its duties and to achieve its objectives, and seeks to ensure that the Board is comprised of directors who have broad and diverse backgrounds, possessing knowledge in areas that are of importance to us. In addition, the Compensation, Nominating and Governance Committee believes it is important that at least one director have the requisite experience and expertise to be designated as an “audit committee financial expert.” The Compensation, Nominating and Governance Committee looks at each nominee on a case-by-case basis regardless of who recommended the nominee. In looking at the qualifications of each candidate to determine if their election would further the goals described above, the Compensation, Nominating and Governance Committee takes into account all factors it considers appropriate, which may include strength of character, mature judgment, career specialization, relevant technical skills or financial acumen, diversity of viewpoint and industry knowledge. Each director nominee must display high personal and professional ethics, integrity and values and sound business judgment.

 

The Compensation, Nominating and Governance Committee was formed in September 2012 and held four meetings during 2014. Prior to the formation of the Compensation, Nominating and Governance Committee, the entire Board as a whole acted as the Company’s Compensation, Nominating and Governance Committee.

 

 

Item 11.    Executive Compensation.

 

Summary Compensation Table

 

The following table sets forth information relating to compensation awarded to, earned by or paid to our Chief Executive Officer, President and Chief Financial Officer, Treasurer and Secretary by the Company during the fiscal years ended December 31, 2014 and 2013.

 

Name and Principal Position		Year			Salary ($)				Stock Awards ($) (1)				Non-Equity Incentive Plan Compensation ($)				All Other Compensation ($)(2)				Total ($)
Patrick R. McDonald Chief Executive Officer		2014 2013			300,000 300,000				236,000 256,000				343,560 294,240				128,869 97,390				1,008,429 947,630
Mark D. Pierce President		2014 2013			225,000 200,000				118,000 128,000				137,424 137,696				23,967 26,710				504,391 492,406
Kevin D. Struzeski Chief Financial Officer, Treasurer and Secretary (1)		2014 2013			235,000 225,000				118,000 128,000				154,602 148,658				73,804 71,535				581,406 573,193

 

(1)	Reflects the full grant date fair value of restricted stock awards granted in 2014 and 2013 calculated in accordance with FASB ASC Topic 718.

 

(2)	All Other Compensation in 2014 and 2013 was comprised of (i) unused vacation, (ii) contributions made by the Company or Nytis Exploration Company to its 401(k) plans, (iii) premiums paid on life insurance policies on such employee’s life, and (iv) other taxable fringe benefits.

 

Narrative Disclosure to Summary Compensation Table

 

The Compensation, Nominating and Governance Committee is charged with reviewing and approving the terms and structure of the compensation of the Company’s executive officers.  The Company has not retained an independent compensation consultant to assist the Company to review and analyze the structure and terms of the Company’s executive officers.

 

The Company considers various factors when evaluating and determining the compensation terms and structure of its executive officers, including the following:

  

	1.	The executive’s leadership and operational performance and potential to enhance long-term value to the Company’s stockholders;
	2.	The Company’s financial resources, results of operations, and financial projections;

 

	3.	Performance compared to the financial, operational and strategic goals established for the Company;
	4.	The nature, scope and level of the executive’s responsibilities;
	5.	Competitive market compensation paid by other companies for similar positions, experience and performance levels; and
	6.	The executive’s current salary and the appropriate balance between incentives for long-term and short-term performance.

 

 

Company management is responsible for reviewing the base salary, annual bonus and long-term compensation levels for other Company employees, and the Company expects this practice to continue going forward.  The Compensation, Nominating and Governance Committee is responsible for significant changes to, or adoption of, employee benefit plans.

 

The Company believes that the compensation environment for qualified professionals in the industry in which we operate is highly competitive.  In order to compete in this environment, the compensation of our executive officers is primarily comprised of the following four components:

 

	Ø	Base salary;
	Ø	2011 Stock Incentive Plan benefits;
	Ø	Annual Incentive Plan Payments; and
	Ø	Other employment benefits.

  

Base Salary. Base salary, paid in cash, is the first element of compensation to our officers. In determining base salaries for our key executive officers, the Company aims to set base salaries at a level we believe enables us to hire and retain individuals in a competitive environment and to reward individual performance and contribution to our overall business goals. The Board of Directors and the Compensation, Nominating and Governance Committee believe that base salary should be relatively stable over time, providing the executive a dependable level of compensation, which is approximately equivalent to compensation that may be paid by competitors for persons of similar abilities. The Board of Directors and the Compensation, Nominating and Governance Committee believes that base salaries for our executive officers are appropriate and are commensurate with base salaries for persons serving as executive officers of public companies similar in size and complexity to the Company.

 

2011 Stock Incentive Plan Benefits. Each of the Company’s executive officers is eligible to be granted awards under the Company’s equity compensation plans.  The Company believes that equity based compensation helps align management and executives’ interests with the interests of our stockholders. Our equity incentives are also intended to reward the attainment of long-term corporate objectives by our executives. We also believe that grants of equity-based compensation are necessary to enable us to be competitive from a total remuneration standpoint.  At the present time, we have one equity incentive plan for our management and employees, the 2011 Stock Incentive Plan. We have no set formula for granting awards to our executives or employees. In determining whether to grant awards and the amount of any awards, we take into consideration discretionary factors such as the individual’s current and expected future performance, level of responsibilities, retention considerations and the total compensation package.

 

Annual Incentive Plan.  Cash payments made under the provisions of the Company’s Annual Incentive Plan (“AIP”) is another component of our compensation plan.  The Board of Directors and the Compensation, Nominating and Governance Committee believes that it is appropriate that executive officers and other employees have the potential to receive a portion of their annual compensation based upon the achievement of defined objectives in order to encourage performance to achieve these key corporate objectives and to be competitive from a total remuneration standpoint.

 

In general terms, the Annual Incentive Plans are designed to meet the following objectives:

 

●

Provide an incentive plan framework that is performance-driven and focused on objectives that were critical to Carbon’s success during the plan period dates;

 

●

Offer competitive cash compensation opportunities to the executive officers and all employees;

 

●

Incentivize and reward outstanding achievement; and

 

●

Incentivize the creation of new assets, plays and values.

 

In addition, the Annual Incentive Plans provided cash pools for all employees. Once the pools were established, awards were allocated by the executive officers to individuals based on their assessment as to individual or group performances.

 

Payments in 2014 were determined under the provisions of the Carbon Natural Gas Company 2013 Annual Incentive Plan whereby forty percent of the AIP payments were determined at the discretion of the Board taking into consideration the factors listed above and sixty percent of the AIP payments were determined and weighted based upon the performance measures and objectives as follows:

 

Performance Measure		Weighting				Objective
EBITDA per Debt Adjusted Share Growth			16.67	%		75.0% increase
Net Total Proved Reserve Growth			16.67	%		15.0% increase
Net Annual Production Growth			16.67	%		20.0% increase
Lease Operating Expenses ($/unit)			16.67	%		$1.00/Mcfe (6:1 equivalent basis)
G&A per Unit of Production ($/unit)			16.66	%		$1.00 per unit of production equivalent
F&D cost per Unit of Reserves			16.66	%		$.75 per unit of reserve equivalent
Total of Performance Measures			100.00	%

 

 

Payments in 2013 were determined under the provisions of the Carbon Natural Gas Company 2012 Annual Incentive Plan whereby forty percent of the AIP payments were determined at the discretion of the Board taking into consideration the factors listed above and sixty percent of the AIP payments were determined and weighted based upon the performance measures and objectives as follows:

 

Performance Measure		Weighting				Objective
Total Shareholder Return			20	%		Rank Within Peer Group
EBITDA per Debt Adjusted Share Growth			20	%		7.5% Increase
Net Total Proved Reserve Growth			20	%		7.5% Increase
Net Annual Production Growth			20	%		7.5% Increase
Lease Operations Expense ($/Unit)			20	%		$1.20/Mcfe (6:1 equivalent basis)

  

Other Compensation/Benefits. Another element of the overall compensation is through providing our executive officers various employment benefits, such as the payment of health and life insurance premiums on behalf of the executive officers.   Our executive officers are also eligible to participate in our 401(k) plans on the same basis as other employees and the Company historically has made matching contributions to the 401(k) plan, including for the benefit of our executive officers.

 

Pursuant to the employment agreements with Messrs. McDonald, Pierce and Struzeski, such officers are entitled to certain payments upon termination of employment. Other than these arrangements, we currently do not have any compensatory plans or arrangements that provide for any payments or benefits upon the resignation, retirement or any other termination of any of our executive officers, as the result of a change in control, or from a change in any executive officer’s responsibilities following a change in control.

 

Director Compensation

 

We use a combination of cash and equity incentive compensation in the form of restricted stock to attract and retain qualified and experienced candidates to serve on the Board. In setting this compensation, our Compensation, Nominating and Governance Committee considers the significant amount of time and energy expended and the skill-level required by our directors in fulfilling their duties. Grants of shares of restricted stock vest upon the earlier of a change in control of the Company or the date a non-management director’s membership on the Board is terminated other than for cause. We also reimburse expenses incurred by our non-employee directors to attend Board and Board committee meetings.

 

The following table reports compensation earned by or paid to our non-employee directors during 2014.

 

		Fees Earned or
		Paid in Cash
Name(1)(2)(3)		($)
James H. Brandi			30,000
David H. Kennedy			-
Bryan H. Lawrence			-
Peter A. Leidel			-
Edwin H. Morgens			20,000

 

(1)

Mr. McDonald, our Chief Executive Officer, is not included in this table as he is an employee of ours and receives no separate compensation for his services as a director. The compensation received by Mr. McDonald as an employee is shown below under “Executive Compensation – Summary Compensation Table.”

 

(2)	During 2014, Messrs. Brandi, Lawrence, Leidel and Morgens were each awarded 80,000 restricted shares of our common stock. The aggregate number of unvested restricted stock awards outstanding at December 31, 2014 for each of our four non-employee directors other than Mr. Kennedy is 240,000.

 

(3)	Mr. Kennedy has been a Director of the Company since December 11, 2014. Prospectively, he will receive compensation in line with our other non-employee directors.

 

 

Outstanding Equity Awards at December 31, 2014

 

The following tables sets forth information concerning unexercised stock options, warrants, and unvested restricted stock and performance unit awards, each as held by our executive officers as of December 31, 2014.

  

OPTION AWARDS (1)

Award Recipient

Option for # of Shares

# Vested

Exercise Price per Share

Date Granted

Expiration

Kevin D. Struzeski

163,076

163,076

$

0.61

3/16/2006

1/1/2016

 

  

WARRANT AWARDS (1)
Award Recipient		Option for # of Shares				# Vested				Exercise Price per Share				Date Granted		Expiration
Patrick R. McDonald (2)			2,446,133				2,446,133			$	0.85			05/19/2005		06/01/2015
Former SLSC Officers and Directors			250,000				250,000			$	1.00			01/10/2007		08/31/2017
			2,696,133				2,696,133

  

STOCK AWARDS
		Equity Incentive Plan Awards								Market Value
		# of Unvested Shares								of Unvested
		Restricted				Performance				Shares
Award Recipient		Stock				Units				$(3)
Patrick R. McDonald			1,131,837	(1)							724,375
			800,001				1,361,600				1,383,425
			1,931,838				1,361,600				2,107,800
Mark D. Pierce			30,577	(1)							19,569
			399,999				730,800				723,711
			430,576				730,800				743,280
Kevin D. Struzeski			305,767	(1)							195,691
			399,999				730,800				723,711
			705,766				730,800				919,402

  

The following table reflects unvested stock awards held by our executive officers as of December 31, 2014 that have time-based vesting. These stock awards will vest as follows if the named executive officer has remained in continuous employment through each such date:

Award Recipient		2015				2016				2017				Thereafter
Patrick R. McDonald			777,279				643,946				510,613				-
Mark D. Pierce			210,192				143,525				76,859				-
Kevin D. Struzeski			301,922				235,255				168,589				-

 

 

The following table reflects unvested performance stock awards held by our executive officers as of December 31, 2014 that vest either upon a change in control of the Company or based upon 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 properties) per share relative to a defined peer group. These performance stock awards will vest as follows if the named executive officer has remained in continuous employment with the Company through the date of a change in control and if the executive officer earns 100% of the performance stock award based upon the achievement of the price of the Company’s stock and the performance measures mentioned above relative to its peer group:

 

		Change				Stock Price and Defined Performance Measures Relative to
Stock Award Recipient		of Control				Peer Group
Patrick R. McDonald			361,600				1,000,000
Mark D. Pierce			180,800				550,000
Kevin D. Struzeski			180,800				550,000

 

(1)	Awards made by Nytis USA prior to the Merger and were assumed as a result of the Merger, the number of shares and the exercise price, when applicable, have been adjusted in line with the exchange ratio of Nytis USA shares for Company shares in the Merger.

 

(2)	Grantee is McDonald Energy LLC, over which Mr. McDonald has voting and investment power.

 

(3)	Reflects the value of unvested shares of restricted stock and performance unit awards held by our executive officers as of December 31, 2014 measured by the closing market price of our common stock on December 31, 2014, which was $0.64 per share.

 

Employment Contracts and Termination of Employment and Change-in-Control Arrangements

 

Effective March 30, 2013, Messrs. McDonald, Pierce and Struzeski entered into employment agreements with the Company. These agreements superseded employment agreements between Messrs. McDonald and Struzeski and Nytis Exploration Company and between Mr. Pierce and Nytis LLC.

 

The agreement between the Company and Patrick R. McDonald has an "Initial Term" through December 31, 2015, which term shall automatically be extended for successive terms of one-year provided, however, that the Board of Directors may terminate the agreement as of the end of the Initial Term or any additional term by giving written notice of termination at least three months preceding the end of the then current term. In the event of the termination of Mr. McDonald’s employment, Mr. McDonald is to receive an amount equal to the greater of (i) all base salary and other compensation due under the terms of the agreement over the remainder of the Initial Term or (ii) 150% of his "Compensation,” defined as the arithmetic average of Mr. McDonald’s annual base salary, bonus and other cash compensation for each of the three years prior to the termination and for a period of 24 months from the date of termination, his medical, dental, disability and life insurance coverage at the same levels of coverage as in effect immediately prior to his termination. In the event of termination within two years after a change in control of the Company, he is to receive 275% of the Compensation (as defined above).

 

The agreements between the Company and Messrs. Pierce and Struzeski have an "Initial Term" through December 31, 2015, which term shall automatically be extended for successive terms of one-year provided, however, that the Board of Directors may terminate the agreement as of the end of the Initial Term or any additional term by giving written notice of termination at least three months preceding the end of the then current term. In the event of the termination of Mr. Pierce’s or Mr. Struzeski's employment, they would receive an amount equal to the greater of (i) all base salary and other compensation due under the terms of the agreement over the remainder of the Initial Term or (ii) 100% of his "Compensation,” defined as the arithmetic average of their annual base salary, bonus and other cash compensation for each of the three years prior to the termination and the cost to provide benefits for a period of 12 months from the date of termination at the same levels of coverage as in effect immediately prior to the date of termination. In the event of termination within two years after a change in control of the Company, they would receive 200% of their Compensation (as defined above) and 100% of the annual cost to the Company of the benefits provided to Messrs. Pierce and Struzeski.

 

 

Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

 

As of March 6, 2015 the Company had 106,875,447 shares of common stock outstanding. The following sets forth certain information about the number of common shares owned by (i) each person (including any group) known to us that beneficially owns five percent or more of the common shares (the only class of the Company’s voting securities), (ii) each of our directors and named executive officers, and (iii) all named executive officers and directors as a group.  Unless otherwise indicated, the stockholders possess sole voting and investment power with respect to the shares shown. The business address for each of the Company’s officers and directors is 1700 Broadway, Suite 1170, Denver, Colorado 80290.

 

Name and Address of Beneficial Owner		Amount of Beneficial Ownership(1)				Percent of Class(2)
5% Stockholders
Yorktown Energy Partners V, L.P. 410 Park Avenue, 19th Floor New York, NY 10022			17,938,309				16.8	%
Yorktown Energy Partners VI, L.P., 410 Park Avenue, 19th Floor New York, NY 10022			17,938,309				16.8	%
Yorktown Energy Partners IX, L.P., 410 Park Avenue, 19th Floor New York, NY 10022			22,222,222				20.8	%
Arbiter Partners Capital Management LLC 11 East 44th Street, Suite 700 New York, NY 10017			12,440,001				11.6	%
AWM Investment Company Inc. (3) c/o Special Situation Funds 527 Madison Avenue Suite 2600 New York, New York 10022			10,888,889				10.2	%
Wynnefield Capital (4) 450 Seventh Avenue Suite 509 New York, New York 10123			6,444,445				6.0	%

  

  

Name of Beneficial Owner		Amount of Beneficial Ownership(1)				Percentage(2)
Executive Officers and Directors
James H. Brandi, Director (5)			-				*
David H. Kennedy, Director (6)			163,076				*
Bryan H. Lawrence, Director (7)			58,098,840				54.4	%
Peter A. Leidel, Director (8)			58,098,840				54.4	%
Patrick R. McDonald, Chief Executive Officer and Director (9)			4,988,924				4.5	%
Edwin H. Morgens, Director (10)			1,666,667				1.6	%
Mark D. Pierce, President (11)			416,703				*
Kevin D. Struzeski, Chief Financial Officer, Treasurer and Secretary (12)			949,445				*
All directors and executive officers as a group (seven persons) (13)			66,283,655				60.1	%

 

* less than 1%

 

(1)

Under Rule 13d-3, a beneficial owner of a security includes any person who, directly or indirectly, through any contract, arrangement, understanding, relationship, or otherwise has or shares: (i) voting power, which includes the power to vote, or to direct the voting of shares; and (ii) investment power, which includes the power to dispose or direct the disposition of shares.  Certain shares may be deemed to be beneficially owned by more than one person (if, for example, persons share the power to vote or the power to dispose of the shares).  In addition, shares are deemed to be beneficially owned by a person if the person has the right to acquire the shares (for example, upon exercise of an option) within 60 days of the date as of which the information is provided.  In computing the percentage ownership of any person, the amount of shares outstanding is deemed to include the amount of shares beneficially owned by such person (and only such person) by reason of these acquisition rights.

 

(2)	Calculated in accordance with Rule 13d-3 under the Securities Exchange Act of 1934. Percentages are rounded to the nearest one-tenth of one percent.

 

(3)

Consists of (i) 7,555,556 common stock shares owned by Special Situations Fund III QP, L.P. (“SSFQP”), (ii) 2,222,222 common stock shares owned by Special Situations Cayman Fund, L.P. (“Cayman”) and (iii) 1,111,111 common stock shares owned by Special Situations Private Equity Fund L.P. (“SSPE”). AWM Investment Company, Inc., a Delaware Corporation (“AWM”) is the investment advisor to SSFQP, Cayman and SSPE. AWM holds sole voting and investment power over these shares.

 

(4)

Includes (i) 2,887,111 common stock shares owned by Wynnefield Partners Small Cap Value, LP I, (ii) 1,997,778 common stock shares owned by Wynnefield Partners Small Cap Value, LP and (iii) 1,559,556 common stock shares owned by Wynnefield Small Cap Value Offshore Fund, Ltd., over which Wynnefield Capital has voting and investment power.

 

(5)	Does not include 340,000 restricted shares of our common stock, which vest upon the earlier of a change in control of the Company or the date the director’s membership on the Board is terminated other than for cause.

 

(6)	Does not include 80,000 restricted stock shares of our common stock which vest upon the earlier of a change in control of the Company or the date the director’s membership on the Board is terminated other than for cause.

 

(7)

Includes (i) 17,938,309 common stock shares owned by Yorktown Energy Partners V, L.P., (ii) 17,938,309 common stock shares owned by Yorktown Energy Partners VI, L.P. and (iii) 22,222,222 common stock shares owned by Yorktown Energy Partners IX, L.P. over which Mr. Lawrence and Mr. Leidel have voting and investment power. Does not include 320,000 restricted shares of our common stock, which vest upon the earlier of a change in control of the Company or the date the director’s membership on the Board is terminated other than for cause.

 

 

(8)

Includes (i) 17,938,309 common stock shares owned by Yorktown Energy Partners V, L.P., (ii) 17,938,309 common stock shares owned by Yorktown Energy Partners VI, L.P. and (iii) 22,222,222 common stock shares owned by Yorktown Energy Partners IX, L.P. over which Mr. Lawrence and Mr. Leidel have voting and investment power. Does not include 320,000 restricted shares of our common stock, which vest upon the earlier of a change in control of the Company or the date the director’s membership on the Board is terminated other than for cause.

 

(9)

Includes (i) 482,704 shares owned by McDonald Energy, LLC over which Mr. McDonald has voting and investment power, (ii) stock purchase warrants held by McDonald Energy, LLC exercisable for 2,446,133 shares of common stock and (iii) 400,000 shares of restricted stock that will vest within 60 days. Does not include 400,001 and 1,361,600 shares of unvested restricted and performance units, respectively.

 

(10)	Does not include 320,000 restricted shares of our common stock, which vest upon the earlier of a change in control of the Company or the date the director’s membership on the Board is terminated other than for cause.

 

(11)	Includes 200,000 shares of restricted stock that will vest within 60 days. Does not include 199,999 and 730,800 shares of unvested restricted stock and performance units, respectively.

 

(12)	Includes (i) stock options exercisable for 163,076 shares of common stock and 200,000 shares of restricted stock that will vest within 60 days. Does not include 199,000 and 730,800 shares of unvested restricted stock and performance units, respectively.

 

(13)	The shares over which both Mr. Lawrence and Mr. Leidel have voting and investment power are the same shares and the percentage of total shares has not been aggregated for purposes of these calculations.

 

Equity Compensation Plans

 

Our Board of Directors has adopted the 2011 Stock Incentive Plan (the “Plan”) and such Plan was approved by the stockholders on December 8, 2011 at the annual meeting of stockholders. As of December 31, 2013 the Company has issued 3,210,000 restricted shares and 3,086,160 restricted performance units under the plan. Information regarding options outstanding as December 31, 2014 is set forth under the heading “Market for Common Equity and Related Stockholder Matters - Securities Authorized for Issuance Under Equity Compensation Plans” above.

  

Item 13.    Certain Relationships and Related Transactions, and Director Independence.

 

Certain Relationships

 

Nytis Exploration Company is an independent oil and gas company that engages in the exploration, development, production, marketing and sale of oil, gas, coalbed methane and other hydrocarbons in locations outside of the United States. In 2013, Nytis Exploration Company filed a certificate of corporate dissolution with the State of Delaware. Carbon and Nytis Exploration Company are related in that the same individuals serve as directors of both corporations and, prior to the closing of the Private Placement, a majority of the outstanding stock of each corporation was owned by the same stockholders. However, Nytis Exploration Company is not currently a direct or indirect subsidiary of the Company. Mr. McDonald and Mr. Struzeski provide a limited amount of services to Nytis Exploration Company as it winds up its activities.

 

Related Transactions

 

The following sets forth information regarding transactions between the Company (and its subsidiaries) and its officers, directors and significant stockholders since January 1, 2014.

 

Employment Agreements

 

See the Executive Compensation section of this Annual Report for a discussion of the employment agreement between Messrs. McDonald, Pierce and Struzeski and the Company.

 

Stock Purchase Agreement

 

Pursuant to a Stock Purchase Agreement dated June 9, 2014, the Company purchased approximately 8.2 million shares of the Company’s common stock from a 5% beneficial shareholder, RBCP Energy Fund Investments LP, for a purchase price of $0.40 per share for aggregate consideration of approximately $3.3 million.

 

Director Independence

 

The Company’s Board consists of Messrs. Brandi, Kennedy, Lawrence, Leidel, McDonald and Morgens. The Company utilizes the definition of “independent” as it is set forth in Rule 5605(a)(2) of the Nasdaq Listing Rules. Further, the Board considers all relevant facts and circumstances in its determination of independence of all members of the board (including any relationships). Based on the foregoing criteria, Messrs. Brandi, Kennedy and Morgens are considered to be independent directors.

 

 

Item 14.    Principal Accountant Fees and Services.

 

Audit and Audit Related Service Fees

 

Our independent registered public accounting firm, EKS&H LLLP (“EKSH”) billed us aggregate fees in the amount of approximately $164,000 and $160,000 for the fiscal years ended December 31, 2014 and 2013, respectively. These amounts were billed for professional services that EKSH provided for the audit of our annual financial statements, review of the interim Consolidated Financial Statements included in our reports on Forms 10-Q, and other services typically provided by an auditor in connection with statutory and regulatory filings or engagements for those fiscal years.

 

Tax Fees

 

EKSH did not bill us for any tax fees for the fiscal years ended December 31, 2014 and 2013.

 

All Other Fees

 

EKSH billed us for permitted, pre-approved information technology support fees of $41,000 and $67,000 for the fiscal years ended December 31, 2014 and 2013, respectively.

 

Audit Committee’s Pre-Approval Practice

 

Section 10A(i) of the 1934 Act prohibits our auditors from performing audit services for us as well as any services not considered to be “audit services” unless such services are pre-approved by the Audit Committee.

 

The Board of Directors adopted resolutions that provided that the Board must:

 

Pre-approve all audit services that the auditor may provide to us or any subsidiary (including, without limitation, providing comfort letters in connection with securities underwritings or statutory audits) as required by §10A(i)(A) of the 1934 Act.

 

Pre-approve all non-audit services (other than certain de minimis services described in §10A(i)(1)(B) of the 1934 Act that the auditors propose to provide to us or any of our subsidiaries.

 

The Audit Committee considers at each of its meetings whether to approve any audit services or non-audit services. In some cases, management may present the request; in other cases, the auditors may present the request. The Board of Directors approved EKSH performing our audit for the 2014 fiscal year.

 

 

PART IV

 

Item 15.    Exhibits, Financial Statement Schedules.

 

(a)    The following documents are filed as part of this report or are incorporated by reference:

 

(1)   Financial Statements:

 

1.      Report of Independent Registered Public Accounting Firm

 

2.      Consolidated Balance Sheets—December 31, 2014 and 2013

 

3.      Consolidated Statements of Operations—Years Ended December 31, 2014 and 2013

 

4.      Consolidated Statements of Shareholders' Equity—Years Ended December 31, 2014 and 2013

 

5.      Consolidated Statements of Cash Flows—Years Ended December 31, 2014 and 2013

 

6.      Notes to Consolidated Financial Statements—Years Ended December 31, 2014 and 2013

 

(2)    Financial Statement Schedules: All schedules have been omitted because the information is either not required or is set forth in the financial statements or the notes thereto.

 

(3)    Exhibits: See the Index of Exhibits listed in Item 15(b) hereof for a list of those exhibits filed as part of this Annual Report on Form 10-K.

 

 

(b)    Index of Exhibits:

 

Exhibit No.		Description
2.1		Agreement and Plan of Merger dated January 31, 2011 by and among the Company, St. Lawrence Merger Sub, Inc. and Nytis Exploration (USA), Inc., incorporated by reference to Exhibit 2.1 to Form 8-K filed February 1, 2011.
2.2		Participation Agreement by and between the Company, Nytis Exploration Company LLC and Liberty Energy LLC, dated September 17, 2012, incorporated by reference to Exhibit 2.2 to Form 10-Q filed on November 14, 2014.
2.3		Participation Agreement by and between the Company, Nytis Exploration Company LLC and Liberty Energy LLC, dated February 25, 2014, incorporated by reference to Exhibit 2.3 to Form 10-Q filed on November 14, 2014.
2.4		Addendum to Participation Agreement by and between the Company, Nytis Exploration Company LLC and Liberty Energy LLC, dated February 26, 2014, incorporated by reference to Exhibit 2.4 to Form 10-Q filed on November 14, 2014.
2.5*		Purchase and Sale Agreement by and among Nytis Exploration Company LLC, Liberty Energy, LLC and Continental Resources, Inc., dated October 15, 2014.  Portions of the Purchase and Sale Agreement have been omitted pursuant to a request for confidential treatment.
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 filed on May 5, 2011.
3(i)(b)		Amended and Restated Certificate of Designation with respect to Series A Convertible Preferred Stock or Carbon Natural Gas Company, incorporated by reference to Exhibit 3(i) to Form 8-K 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 filed on July 19, 2011.
3(ii)		Amended and Restated Bylaws of St. Lawrence Seaway Corporation, incorporated by reference to Exhibit 3(i) to Form 8-K/A filed on March 31, 2011.
10.1		Amended and Restated Credit Agreement, by and between Nytis Exploration Company LLC and Bank of Oklahoma, National Association, dated May 31, 2010, incorporated by reference to Exhibit 10.2 to Form 8-K/A filed on March 31, 2011.
10.1(a)		Guaranty from Nytis USA to Bank of Oklahoma, National Association, dated June 21, 2005, incorporated by reference from Exhibit 10.2(a) to Form 8-K/A filed on March 31, 2010.
10.1(b)		Consent of Guarantor and Amendment of Guaranty from Nytis USA to Bank of Oklahoma, National Association, dated May 31, 2010, incorporated by reference to Exhibit 10.2(b) to Form 8-K/A filed on March 31, 2011.
10.2		Second Amendment of Amended and Restated Credit Agreement, Limited Waiver and Borrowing Base Redetermination, by and between Nytis Exploration Company LLC and Bank of Oklahoma, National Association, dated May 31, 2010 as amended on June 10, 2011, incorporated by reference to Exhibit 10.3 to Form S-1 filed on August 12, 2011.
10.3		Guaranty from the Company to Bank of Oklahoma, National Association, dated June 10, 2011, incorporated by reference to Exhibit 10.3 to Form S-1 filed on August 12, 2011.
10.4		Employment Agreement between the Company and Patrick McDonald, incorporated by reference to Exhibit 10.2 to Form 8-K filed on April 5, 2013.
10.5		Employment Agreement between the Company and Mark Pierce, incorporated by reference to Exhibit 10.3 to Form 8-K filed on April 5, 2013.
10.6		Employment Agreement between the Company and Kevin Struzeski, incorporated by reference to Exhibit 10.4 to Form 8-K filed on April 5, 2013.
10.7		Fourth Amendment of Amended and Restated Credit Agreement and Borrowing Base Redetermination by and between Nytis Exploration Company LLC and Bank of Oklahoma, National Association, dated June 28, 2013, incorporated by reference to Exhibit 10.1 to Form 10-Q filed on August 13, 2013.
10.8		Amendment of Guaranty from Nytis Exploration (USA) Inc. to Bank of Oklahoma, National Association, dated June 28, 2013, incorporated by reference to Exhibit 10.2 to Form 10-Q filed on August 13, 2013.
10.9		Amendment of Guaranty from the Company to Bank of Oklahoma, National Association, dated June 28, 2013, incorporated by reference to Exhibit 10.3 to Form 10-Q filed on August 13, 2013.
10.10		Carbon Natural Gas Company 2013 Annual Incentive Plan, incorporated by reference to Exhibit 10.1 to Form 8-K filed on May 20, 2013.
10.11		Carbon Natural Gas Company 2014 Annual Incentive Plan, incorporated by reference to exhibit 10.5 to Form 10-Q for Carbon Natural Gas Company filed on May 14, 2014.
10.12		Stock Purchase Agreement dated June 9, 2014 between Carbon Natural Gas Company and RBCP Energy Fund Investments LP, incorporated by reference to exhibit 10.1 to Form 8-K for Carbon Natural Gas Company filed on June 9, 2014.
14		Code of Ethics, incorporated by reference to Exhibit 14 to Form 10-K filed on June 29, 2004.
21.1*		Subsidiaries of the Company.
23.1*		Consent of EKS&H LLLP regarding the Form S-8 Financials.
23.2*		Consent of Cawley, Gillespie & Associates, Inc.
31.1*		Rule 13a-14(a)/15d-14(a) - Certification of Chief Executive Officer.
31.2*		Rule 13a-14(a)/15d-14(a) - Certification of Chief Financial Officer.
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 Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*		Report of Cawley, Gillespie & Associates, Inc., Independent Petroleum Engineers.
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 limitations of that section.

 

 

SIGNATURES

 

        Pursuant to the requirements of Section 13 or 15(d) 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.

 

Date: March 31, 2015	CARBON NATURAL GAS COMPANY (Registrant)
	By:	/s/ Patrick R. McDonald
		Patrick R. McDonald Chief Executive Officer
	By:	/s/ Kevin D. Struzeski
		Kevin D. Struzeski Chief Financial Officer, Treasurer and Secretary (Principal Financial Officer and Principal Accounting Officer)

  

        Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.

 

Signatures		Title		Date
/s/ Patrick R. McDonald		Director and Chief Executive Officer		March 31, 2015
Patrick R. McDonald		(Principal Executive Officer)
/s/ James H. Brandi		Chairman and Director		March 31, 2015
James H. Brandi
/s/ Peter A. Leidel		Director		March 31, 2015
Peter A. Leidel
/s/ Bryan H. Lawrence		Director		March 31, 2015
Bryan H. Lawrence
/s/ Edwin H. Morgens		Director		March 31, 2015
Edwin H. Morgens
/s/ David H. Kennedy		Director		March 31, 2015
David H. Kennedy

 

 

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