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, 2016

 

or

 

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

 

For the transition period from            to              

 

Commission File Number: 000-02040

 

CARBON NATURAL GAS COMPANY
(Exact Name of Registrant as Specified in Its Charter)

 

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:

 

Common Stock, Par Value $0.01 Per Share

(Title of Class)

 

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).  ☒ 

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. Yes ☐  No ☒ 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See 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, 2016, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $32.9 million (based on the closing price of such stock). 

There were approximately 5.5 million shares (post reverse split) of the registrant's common stock, par value $0.01 per share, outstanding as of March 17, 2017. 

 

 

CARBON NATURAL GAS COMPANY
TABLE OF CONTENTS

 

		Page No.
PART I
Item 1.	Business	1
Item 1A.	Risk Factors	17
Item 1B.	Unresolved Staff Comments	28
Item 2.	Properties	28
Item 3.	Legal Proceedings	28
Item 4.	Mine Safety Disclosures	28
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	29
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	30
Item 8.	Financial Statements and Supplementary Data	45
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	70
Item 9A.	Controls and Procedures	70
Item 9B.	Other Information	70
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	71
Item 11.	Executive Compensation	75
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	80
Item 13.	Certain Relationships and Related Transactions, and Director Independence	82
Item 14.	Principal Accountant Fees and Services	82
PART IV
Item 15.	Exhibits, Financial Statement Schedules	84
	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 acquired oil and natural gas interests (owned by Addington Exploration, LLC (“Addington”)) located 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. 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.

 

●

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

 

●

In October 2016, Nytis LLC completed an acquisition of approximately 2,300 natural gas wells and over 900 miles of associated natural gas gathering pipeline and compression facilities, located primarily in West Virginia. The assets have estimated proved developing producing reserves of approximately 46.4 Bcfe, approximately 201,000 net acres of oil and natural gas mineral interests and were producing approximately 9,000 net Mcfe per day as of December 31, 2016.

 

●

As of December 31, 2016, the Company owned interests in approximately 3,211 gross (2,589 net) productive oil and natural gas wells and approximately 532,000 (466,000 net) acres in the Appalachian and Illinois Basin of which 329,000 (277,000 net) acres are undeveloped.

 

●

On February 15, 2017, the Company entered into an agreement in which Carbon acquired 17.813% interest in Carbon California Company, LLC for no cash consideration. Concurrently, Carbon California Company, LLC completed the acquisition of certain oil and gas assets in the Ventura Basin of California.

 

●

On March 15, 2017 and pursuant to a reverse stock split approved by the shareholders and Board of Directors, each 20 shares of issued and outstanding common stock became one share of common stock and no fractional shares were issued. All references to the number of shares of common stock and per share amounts give retroactive effect to the reverse stock split for all periods presented.

 

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 cash flows, production and reserves through 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 resources in core operating areas. Our focus on the Appalachian and Illinois Basins allows the Company to capitalize on its regional expertise to optimize drilling and completion techniques and to create 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.

 

●

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 as economic conditions allow. During this time, we have enhanced our well performance, improved well drilling and completion performance, including reduced drilling days, increased horizontal lateral length, decreased cost per frac stage and reduced days from spud to first production. In addition we have established an infrastructure of oil and natural gas gathering and salt water handling and disposal facilities which will benefit the economics of future drilling. We continue to acquire leases and producing properties where we have identified additional potential to expand our oil development activities.

 

●

Gas development. Another area of focus of our drilling and completion activities is the development of a coalbed methane resource located in the Illinois Basin. The Company has approximately 62,000 net mineral acres in Indiana and Illinois which are prospective for the development of coalbed methane. The Company also owns an interest in related natural gas gathering and compression and salt water disposal facilities. Since 2006, we have conducted a drilling program in the Seelyville coal formation, including participating as a 50% joint venture partners in the drilling of 36 vertical and two horizontal wells. During 2015, the Company participated in the drilling of 25 stratigraphic wells to identify potential future horizontal locations in the Seelyville coal formation. If natural gas prices support further development of the resource, we may drill additional wells.

 

●

Acquisitions. Our strategy is to increase our reserves and operating cash flows through the acquisition of complementary properties. In October 2016, the Company completed an acquisition of approximately 2,300 natural gas wells located primarily in West Virginia. In February 2017, the Company through its ownership of Carbon California Company, LLC, completed acquisitions of oil and gas assets in the Ventura Basin of California. The Company will continue to focus on the acquisition of complementary properties.

 

●

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.

 

●

Low-risk development drilling in established resource plays, and flexibility in deployment of exploration, development 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, 2016. 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, neither of which require any near term obligatory capital expenditures.

 

●

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 LegacyTexas Bank to fund drilling, completion and acquisition activities and in the past have accessed outside capital through the use of joint ventures or similar arrangements.

 

●

Control over operating decisions and capital program.  At December 31, 2016, we operated approximately 96% of the wells in which we have a working interest. The high percentage of operated wells allows us to manage the timing of capital expenditures, lease operating expenses and the marketing of oil and natural gas production.

 

 

●

Manage commodity price exposure through an active hedging program. We maintain a hedging program designed to reduce exposure to fluctuations in commodity prices. As of December 31, 2016, we have outstanding natural gas hedges of approximately 3.4 million MMBtu for 2017 at an average price of $3.30 per MMBtu, approximately 3.1 million MMBtu for 2018 at an average price of $3.01 per MMBtu and approximately 1.3 million MMBtu for 2019 at an average price of $2.85 per MMBtu. In addition, as of December 31, 2016, we have outstanding oil hedges of 60,000 barrels for 2017 at an average price of $52.98 per barrel, 48,000 barrels for 2018 at an average price of $54.11 per barrel and 36,000 barrels for 2019 at an average price of $54.90 per barrel.

 

●

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 asset 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 various natural gas 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 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, 2016.

 

 

 

Appalachian Basin

 

As of December 31, 2016, Nytis LLC owns working interests in 3,155 gross wells (2,561 net) and royalty interests located in Kentucky, Ohio, Tennessee and West Virginia, and has leasehold positions in approximately 187,000 net developed acres and approximately 215,000 net undeveloped acres.  As of December 31, 2016, net oil and natural gas sales were approximately 15,000 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, 2016, Nytis LLC owns working interests in 56 gross (28 net) coalbed methane wells in the Illinois Basin and has a leasehold position in approximately 1,700 net developed acres and approximately 62,000 net undeveloped acres.  As of December 31, 2016, net natural gas sales were approximately 400 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. We have also evaluated producing oil properties with field development potential in California. The following is a summary of our significant acquisitions and divestitures that influenced the last two years. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 4 to the Consolidated Financial Statements and “Recent Developments” for more information on our acquisitions and dispositions.

 

Acquisitions

 

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

 

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

 

●

Approximately 2,300 natural gas wells and over 900 miles of associated natural gas gathering pipelines and compression facilities operated by the Company. As of December 31, 2016, these wells were producing approximately 9,000 net Mcfe per day (97% natural gas).

 

●

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

 

●

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

 

●

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

 

Divestitures

 

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

 

Pursuant to the PSA, the Sellers reserved (i) a minority working interest in the Deep Rights, (ii) an overriding royalty interest in certain of the Deep Rights and (iii) all rights from the surface to the base of the Clinton formation underlying the leases. In connection with the 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.

 

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

 

Reserves

 

Our proved reserves increased in 2016 primarily due to the acquisition of proved producing properties. The changes in our proved reserves during 2016 are as follows:

 

		2016
		Oil				Natural Gas				Total
		MBbls				MMcf				MMcfe
Proved reserves, beginning of year			598				29,958				33,546
Revisions of previous estimates			110				2,207				2,867
Extensions and discoveries			-				-				-
Production			(79	)			(2,823	)			(3,297	)
Purchases of reserves in-place			253				44,923				46,441
Sales of reserves in-place			-				-				-
Proved reserves, end of year			882				74,265				79,557

 

 

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 present value of estimated future oil and natural gas revenues, net of direct expenses, discounted at an annual rate of 10% (“PV-10”) as of December 31, 2016 and 2015 after consolidating the 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,
		2016				2015
Proved developed reserves:
Natural gas (MMcf)			74,265				29,958
Oil and liquids (MBbl)			851				554
Total proved developed reserves (MMcfe)			79,371				33,282
Proved undeveloped reserves:
Natural gas (MMcf)			-				-
Oil and liquids (MBbl)			31				44
Total proved undeveloped reserves (MMcfe)			186				264
Total proved reserves (MMcfe)			79,557				33,546
Percent developed			99.8	%			99.2	%
PV-10 (thousands)		$	49,344			$	25,032
Average natural gas price used (per Mcf)		$	2.41			$	2.50
Average oil and liquids price used (per Bbl)		$	40.40			$	46.12

 

The estimated quantities of proved reserves for the non-controlling interests of the consolidated partnerships as of December 31, 2016 are approximately 3.1 Bcfe, which is approximately 4% 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, 2016 and 2015.

 

Estimated Proved Reserves Excluding Non-Controlling Interests of Consolidated Partnerships

 

		December 31,
		2016				2015
Proved developed reserves:
Natural gas (MMcf)			71,125				26,972
Oil and liquids (MBbl)			851				554
Total proved developed reserves (MMcfe)			76,231				30,296
Proved undeveloped reserves:
Natural gas (MMcf)			-				-
Oil and liquids (MBbl)			31				44
Total proved undeveloped reserves (MMcfe)			186				264
Total proved reserves (MMcfe)			76,417				30,560
Percent developed			99.7	%			99.1	%
PV-10 (thousands)		$	47,659			$	23,301
Average natural gas price used (per Mcf)		$	2.41			$	2.50
Average oil and liquids price used (per Bbl)		$	40.40			$	46.12

 

 

Preparation of Reserves Estimates

 

Our proved oil and natural gas reserves estimates as of December 31, 2016 and 2015 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, 2016 and 2015 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 17 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 in addition to volumetric analysis. 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 additional internal controls over financial reporting. This process is designed to create assurance that production, revenues and expenses are accurately reflected in the reserve database.
	●	A comparison is made and documented of land and lease records to ownership interest data in the reserve database. This process is designed to create assurance 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 obtained from Platts Gas Daily.  Oil pricing for the first flow day of every month is obtained from the U.S. Energy Information Administration.  At the reporting date, 12-month average prices are determined. Regional variations in pricing and related deductions are similarly obtained and a 12-month average is calculated at year end.

 

For the years ended December 31, 2016 and 2015, Carbon’s independent engineering firm, Cawley, Gillespie & Associates, Inc. (“CGA”) reviewed with Carbon technical personnel field performance and future development plans. 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 Company’s database containing 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 96% of the consolidated proved hydrocarbon reserves presented in the Company’s Consolidated Financial Statements. 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 and accounting staff. He has been involved in reservoir engineering in the Appalachian Basin since 1982. 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 Kentucky, Virginia and West Virginia.

 

Drilling Activities

 

Based on current and expected prices for oil and natural gas during 2016 and 2015, we reduced our drilling activity to manage and optimize the utilization of our capital resources. During 2016, our capital expenditures, other than for oil and natural gas property acquisitions, consisted principally of expanding our gathering facilities to provide greater flexibility in moving our natural gas to markets with more favorable pricing.

 

The following table summarizes the number of wells drilled for the years ended December 31, 2016, 2015 and 2014. 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,
		2016								2015								2014
		Gross				Net				Gross				Net				Gross				Net
Development wells:
Productive (1)			-				-				-				-				17.0				10.5
Non-productive (2)			-				-				-				-				-				-
Total development wells			-				-				-				-				17.0				10.5
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, 2016.

 

		December 31, 2016
		Gross				Net
Gas			2,759				2,170
Oil			452				419
Total			3,211				2,589

 

 

Acreage

 

The following table summarizes gross and net developed and undeveloped acreage by state as of December 31, 2016. 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, 2016
		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				31,442				18,221				34,932				19,966
Kentucky			10,778				9,710				97,768				70,899				108,546				80,609
Ohio			338				338				6,703				6,703				7,041				7,041
Tennessee			160				40				93,683				93,599				93,843				93,639
Virginia			732				679				-				-				732				679
West Virginia			187,858				176,326				55,615				44,090				243,473				220,416
Total			203,356				188,838				328,575				276,876				531,931				465,714

 

Undeveloped Acreage Expirations

 

The following table sets forth gross and net undeveloped acres by state as of December 31, 2016 which are scheduled to expire through December 31, 2019 unless production is established within the spacing unit covering the acreage prior to the expiration date or if the Company extends the terms of a lease by paying delay rentals to the lessor.

 

December 31, 2016
		2017								2018								2019
		Gross				Net				Gross				Net				Gross				Net
Indiana			-				-				-				-				-				-
Illinois			6,547				3,274				928				464				999				499
Kentucky			5,056				3,034				9,910				5,946				10,035				6,180
Ohio			-				-				-				-				-				-
Tennessee			-				-				-				-				-				-
Virginia			-				-				-				-				-				-
West Virginia			5,270				1,666				46				34				3,625				3,625
Total			16,873				7,974				10,884				6,444				14,659				10,304

 

 

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, 2016 and 2015.

 

		Year Ended December 31,
		2016				2015
Production data:
Natural gas (MMcf)			2,823				2,040
Oil and condensate (Bbl)			79,044				101,255
Combined (MMcfe)			3,297				2,646
Gas and oil production revenue (in thousands)		$	10,443			$	10,708
Commodity derivative (loss) gain (in thousands)		$	(2,259	)		$	852
Prices:
Average sales price before effects of hedging;
Natural gas (per Mcf)		$	2.53			$	2.78
Oil and condensate (per Bbl)		$	41.95			$	49.83
Average sale price after effects of hedging:
Natural gas (per Mcf)		$	1.89			$	3.01
Oil and condensate (per Bbl)		$	36.14			$	53.48
Average costs per Mcfe:
Lease operating costs		$	0.96			$	1.10
Transportation costs		$	0.50			$	0.65
Production and property taxes		$	0.25			$	0.33

 

 

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.

 

The Company has historically sold a portion of its gas through fixed price physical delivery contracts to effectively provide gas price hedges.

 

The Company has entered into firm transportation contracts to ensure the transport of certain of its gas production to purchasers. Firm transportation volumes and related demand charges for the remaining term of these contracts at December 31, 2016 are summarized in the table below.

 

Period		Dekatherms per day				Demand Charges
Jan 2017 - Apr 2018			5,530			$	0.20 - $0.65
May 2018 - Mar 2020			3,230			$	0.20 - $0.62
Apr 2020 – May 2020			2,150			$	0.20
Jun 2020 – May 2036			1,000			$	0.20

 

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 development drilling programs, and acquire additional producing properties and leases for future development and exploration. A number of the companies with which we compete with have larger staffs and greater financial and operational resources than we have. Because of the nature of our oil and natural gas assets and management’s experience in developing our reserves and acquiring properties, we believe 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

 

Federal, state, and local agencies have extensive rules and regulations applicable to our oil and natural gas exploration, production and related operations. These laws and regulations may change 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 laws and regulations 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 may 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 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. Although we believe we are in substantial compliance with applicable laws and regulations, such laws and regulations may be amended or reinterpreted. Therefore, we cannot predict the ultimate cost of compliance with these requirements or their effect on our operations.

 

Most states require drilling permits, drilling and operating bonds and the filing of various reports and impose other requirements relating to the exploration and production of oil and natural gas. Many states also have statutes or regulations regarding conservation matters including rules governing the size of drilling and spacing units, the density of wells and the unitization of oil and natural gas properties. The federal and state regulatory burden on the oil and natural gas industry increase our cost of doing business and affects our profitability.

 

 

Federal legislation and regulatory controls have historically affected the prices received for natural gas production. The Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the transportation and sale or resale of natural gas in interstate commerce. In 2005, Congress enacted the Energy Policy Act of 2005 (“EPAct 2005”), which amends the Natural Gas Act (“NGA”) to make it unlawful for any entity, including 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 FERC, or 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 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 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. In 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. In addition, the FERC clarified that other end use purchases and sales are not exempt from the reporting requirements. The monitoring and reporting required by the rules have increased 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.

 

Our sales of oil and natural gas are affected by the availability, terms and cost of transportation. Interstate transportation of oil and natural gas by pipelines is regulated by the FERC pursuant to the Interstate Commerce Act, the Energy Policy Act of 1992 and the rules and regulations promulgated under those laws. Intrastate oil and natural gas pipeline transportation rates may also be subject to regulation by state regulatory commissions. We do not believe that the regulation of oil transportation rates will affect our operations in any way that is materially different that those of our competitors who are similarly situated.

 

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 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.

 

The most significant of these environmental laws that may apply to our operations are as follows:

 

●

The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”) and comparable state statutes which impose liability on owners and operators of certain sites and on persons who dispose of or arrange for the disposal of hazardous substances at sites where hazardous substances releases have occurred or are threatening to occur. Parties responsible for the release or threatened release of hazardous substances under CERCLA may by subject to liability for the cost of cleaning up those substances and for damages to natural resources;

 

●

The Oil Pollution Act of 1990 (“OPA”), subjects owners and operators of facilities to strict and several liability for containment and cleanup costs and certain other damages arising from oil spills, including the government’s response costs. Spills subject to the OPA may result in varying civil and criminal penalties and liabilities;

 

●

The Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statues which govern the treatment, storage and disposal of solid and hazardous waste and authorize the imposition of substantial fines and penalties for noncompliance;

 

 

●

The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act (“CWA”), and analogous state laws that govern the discharge of pollutants, including natural gas wastes, into federal and state waters, including spills and leaks of hydrocarbons and produced water. In April 2015, the EPA proposed new CWA regulations that would prevent onshore unconventional oil and gas wells from discharging wastewater pollutants into public treatment facilities. In June 2015, the EPA adopted a new regulatory definition of “waters of the U.S.,” which governs which waters and wetlands are subject to the CWA. Implementation of the regulation has been stayed pending challenges to the regulation filed in federal court. Depending on whether and how the new definition is implemented, it could significantly expand the jurisdictional reach of the CWA in many states;

 

●

The Safe Drinking Water Act (“SDWA”), which governs the disposal of wastewater in underground injection wells; and

 

●

The Clean Air Act (“CAA”) and similar state and local requirements which govern the emission of pollutants into the air. Greenhouse gas record keeping and reporting requirements under the CAA took effect in 2011 and impose increased administrative and control costs. In August 2015, the EPA proposed new regulations under the CAA to reduce methane emissions from new and modified sources in the oil and gas sector. These regulations were finalized in May 2016.

 

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, these properties may 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 horizontal drilling. Hydraulic fracturing is the process of injecting substances such as water, sand, and other additives under pressure into subsurface formations to create or expand fractures, thus creating a passageway for the release of oil and natural gas.

 

Essentially all of our Appalachian Basin oil and natural gas reserves are subject to or have been subjected to hydraulic fracturing and we expect to continue to employ hydraulic fracturing extensively in future wells that we drill and complete. 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 cost of the stimulation process varies according to well location and reservoir.

 

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. We require these service companies to carry insurance covering incidents that could occur in connection with their activities. In addition, these service companies are responsible for obtaining any regulatory permits necessary for them to perform their service in the relevant geographic location. We have not had any incidents, citations or lawsuits resulting from hydraulic fracture stimulation and we are not presently aware of any such matters.

 

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 minimum 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.

 

While hydraulic fracturing historically has been regulated by state and natural gas commissions, the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation from federal agencies. For example the EPA has asserted that the SDWA applies to hydraulic fracturing involving diesel fuel and in February 2014 it issued final guidance on this subject. The guidance defines the term “diesel fuel”, describes the permitting requirements that apply under SDWA for the underground injection of diesel fuel in hydraulic fracturing and makes recommendations for permit writers. Although the guidance applies only in states where the EPA directly implements the Underground Injection Control Class II program, it could encourage state regulatory authorities to adopt permitting and other requirements for hydraulic fracturing. In April 2015, the EPA published in the Federal Register a proposed rule requiring federal pre-treatment standards for wastewater generated during the hydraulic fracturing process in shale and tight geologic formations (unconventional oil and gas resources). These rules were finalized in June 2016 and took effect in August 2016. Hydraulic fracturing requires the use of a significant volume of water with some resulting “flowback water” as well as “produced water.” The new pre-treatment rules require new and existing shale gas operations to pre-treat wastewater before transferring it to treatment facilities.

 

 

The EPA has conducted a nationwide study into the effects of hydraulic fracturing on drinking water. The EPA issued its final report in December 2016 and concluded that several factors affect the frequency and severity of impacts to drinking water from fracking including water availability, injection of fracking fluids into groundwater resources or into failing wells, and discharge of inadequately treated waste water to surface water or unlined pits. The EPA has indicated that it desires to continue to study the matter. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could result in further regulation of hydraulic fracturing.

 

From time to time, Congress has considered the adoption of legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Many producing states have adopted, or are considering adopting, regulations that could impose more stringent permitting, public disclosure and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether.

 

Any of the above factors could have a material adverse effect on our financial position, results of operations or cash flows and could make it more difficult or costly for us to perform hydraulic fracturing

 

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, 2016, our workforce (including those employed by our subsidiary Nytis LLC) consisted of 55 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 from 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.

 

 

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. Historically, the markets for oil and natural gas have been volatile and are likely to remain so in the future. Oil prices have fallen since reaching highs of over $105.00 per barrel in 2014 and dropped below $28.00 per barrel in February 2016. Natural gas prices have declined from over $4.80 per Mcf in 2014 to below $1.70 per Mcf in March 2016. Although oil and natural gas prices have recovered from the lows experienced during the first quarter of 2016, forecasted prices for both oil and natural gas remain low and uncertain, due to over-supply, substantial inventories and concern over global demand.

 

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. Lower commodity prices may also make it more difficult for us to comply with the covenants and other restrictions under our bank credit facility. 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 Facility,” 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. Future price declines could cause us to take additional 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.”

  

Alternatively, high commodity prices may result in significant mark-to-market losses on our commodity-based derivatives, which may in turn cause us to experience losses.

 

The prices we receive for our oil and natural gas depend upon factors beyond our control, including among others:

 

	●	worldwide, domestic and regional economic conditions impacting the global supply and demand for oil and natural gas;
	●	the price and quantity of imports and exports 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 global and domestic oil and natural gas exploration and production;
	●	the level of global and domestic oil and natural gas inventories;

 

 

	●	prevailing prices for local oil and natural gas price indexes in the areas in which we operate;
	●	global and domestic supply and demand fundamentals and transportation availability;
	●	weather conditions;
	●	technological advances affecting energy supply and consumption;
	●	the price and availability of alternative energy; and
	●	global, domestic, local and foreign governmental regulation and taxes.

 

These and other factors make it difficult to predict future commodity price movements with 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 “The use of derivative instruments used in hedging arrangements could result in financial losses or reduce income.” At December 31, 2016, 93% 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 than to fluctuations in oil prices

 

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

 

We have a $23.0 million bank credit facility with Legacy Texas Bank, the outstanding balance of which was approximately $16.2 million at December 31, 2016. We may incur more debt in the future. This indebtedness may have 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 are at variable interest rates, making us vulnerable to increases in interest rates.

 

Our estimates of proved reserves at December 31, 2016 and 2015 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, 2016 and 2015 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. 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 level 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.

 

Less than 1% of our total proved reserves as of December 31, 2016 were undeveloped and those reserves may not ultimately be developed or produced.

 

As of December 31, 2016, less than 1% of our total proved reserves were undeveloped. 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 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. Because the ceiling calculation requires a rolling 12-month average commodity price, due to the effect of lower prices in 2016 and 2015, the Company recognized impairments of approximately $4.3 million and $5.4 million for the years ended December 31, 2016 and 2015, respectively. Impairment charges do not affect cash flows from operating activities, but do adversely affect net income and stockholders’ equity. 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.

 

In addition, impairments 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. Any recorded impairment is not reversible at a later date.

 

 

Our exploration and development projects and acquisitions 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 $8.8 million and $3.1 million in 2016 and 2015, respectively.

 

The Company anticipates its budget for exploration and development work on existing acreage will range between $2.0 million and $5.0 million for 2017 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, especially in regard to potential acquisitions, may exceed those resources and require a substantial increase in capitalization through the issuance of debt or equity securities, sale of assets, delays in planned exploration, development and completion activities or the use of outside capital through joint ventures or similar arrangements. 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 commodity prices may 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 or obtain the debt and/or equity capital necessary to sustain operations. Our Company, like the majority of smaller and mid-size independent oil and gas exploration companies must continue acquiring and developing properties to replace depleting reserves. The budget for these activities often will not be fully funded by operating cash flow. Accordingly, the inability to access 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, 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 for development only if oil and gas prices warrant drilling over a substantial number of 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 provide the substantial amount of capital that would be necessary to drill our potential drilling locations.

 

At an appropriate level of oil and natural gas prices, the Company has a multi-year drilling inventory of 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 may be found to be inaccurate which could have a material adverse effect on us. The combined net acreage expiring in the next three years represents approximately 9% of our total net undeveloped acreage at December 31, 2016.

 

 

Some of these undeveloped leases will allow us to hold only a portion of the lease even after one or more wells have been completed. Management continually prioritizes the ranking and timing of drilling locations based on 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. Our business strategy is to grow production and reserves through acquisitions and through exploration and development drilling. Unless we conduct successful exploration, development and production activities or acquire properties containing proved reserves, our proved reserves will decline as our existing 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 our 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 acquisition, exploration, development and production activities. These activities 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 any particular project. Many factors may curtail, delay or cancel scheduled drilling and production 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 under acceptable terms;
	●	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 may drill in new or emerging plays. As a result, drilling in these areas is subject to greater risk and uncertainty.

 

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 reserve 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.

 

 

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 adequate insurance coverage against some, but not all, potential losses, including hydraulic fracturing. We do not believe that insurance coverage for every environmental damage that could occur is available at a reasonable cost. In the fracturing process, an accidental release could result in possible environmental damage. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. 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 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 addition, our liability for environmental hazards may include conditions created by the previous owner of properties that we purchase or lease.

 

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

 

We may engage in the use of derivative instruments used in hedging arrangements for a significant part of our 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, additional collateral may be required and our cash available for use in our operations would be reduced. A lower amount of available cash 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, oil and natural gas prices and interest rates.

 

As of December 31, 2016, the fair value of the contracts with our derivatives counterparty was a liability of approximately $1.9 million.

 

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 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 gathering or transportation systems, 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 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 apparent. 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 may not be able to generate enough cash flow to meet our debt obligations and fund our other liquidity needs.

 

At December 31, 2016, our debt consisted of approximately $16.2 million in borrowings under the Company’s $23.0 million credit facility. In addition to interest expense and principal on our long-term debt, we have demands on our cash resources including, among others, operating expenses and capital expenditures. 

 

Our ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon future performance and our ability to repay or refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by economic and capital market conditions, results of operations and other factors, many of which are beyond our control. Our ability to meet our debt service obligations also may be impacted by changes in prevailing interest rates, as borrowing under our existing revolving credit facility bears interest at floating rates.

 

We may not generate sufficient cash flow from operations. Without sufficient cash flow, there may not be adequate future sources of capital to enable us to service our indebtedness or to fund our other liquidity needs. If we are unable to service our indebtedness and fund our operating costs, we will be required to adopt alternative strategies that may include:

 

	●	reducing or delaying capital expenditures;
	●	seeking additional debt financing or equity capital;
	●	selling assets;
	●	restructuring or refinancing debt; or
	●	obtaining capital through joint ventures or similar arrangements.

 

We may not be able to complete such alternative strategies on satisfactory terms, if at all. Our inability to generate sufficient cash flows to satisfy our debt obligations and fund our liquidity needs, or to refinance our indebtedness on commercially reasonable terms, would materially and adversely affect our financial condition and results of operations. The formation of joint ventures or other similar arrangements to finance operations may result in dilution of the Company’s interest in the properties affected by such arrangements.

 

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, over the last few years, several bills have been introduced in Congress that, if adopted, 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. Additionally, the Bureau of Land Management, acting under its authority pursuant to the Mineral Leasing Act of 1920, finalized new regulations in January 2017 that aim to reduce waste of natural gas from federal and tribal leasehold by imposing new venting, flaring, and leak detection and repair requirements. 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 and enforcement policies relating to protection of the environment, health and safety. 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 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 early 2016, the EPA announced it would commence a formal process requiring companies operating existing oil and gas sources to provide information to assist in the development of comprehensive regulations to reduce methane emissions. 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.

 

Environmental legislation and regulatory initiatives, including those relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

 

We are subject to extensive federal, state and local laws and regulations concerning environmental protection. Government authorities frequently add to those regulations. Both oil and gas development generally and hydraulic fracturing in particular, are receiving increased regulatory attention.

 

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. To date, no incidents, citations or suits have resulted from our hydraulic fracturing operations. However, the regulatory environment may change with respect to the use of hydraulic fracturing. Any increase in compliance costs could negatively impact our ability to conduct our business.

 

Activists have attempted to link hydraulic fracturing to various environmental problems, including potential adverse effects on drinking water supplies as well as migration of methane and other hydrocarbons. While hydraulic fracturing historically has been regulated by state and natural gas commissions, the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation from federal and state agencies. The EPA has conducted a nationwide study into the effects of hydraulic fracturing on drinking water. The draft report did not find evidence of widespread systemic impacts to drinking water, but did find site-specific impacts. The EPA noted that these results could indicate that such effects are rare or that other limiting factors exist. A public comment period on the report was open until August 25, 2015 and a series of public hearings were conducted by the EPA throughout the fall of 2015. The EPA issued its final report in December 2016 and concluded that several factors affect the frequency and severity of impacts to drinking water from fracking including water availability, injection of fracking fluids into groundwater resources or into failing wells, and discharge of inadequately treated waste water to surface water or unlined pits. The EPA has indicated that it desires to continue to study the matter. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could result in further regulation of hydraulic fracturing.

 

 

From time to time Congress has considered the adoption of legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Federal agencies have imposed limits on hydraulic fracturing activities on federal lands and many producing states have adopted, or are considering adopting, regulations that could impose more stringent permitting, public disclosure and well construction requirements on hydraulic fracturing operations.

 

Any of the above factors could have a material adverse effect on our financial position, results of operations or cash flows and could make it more difficult or costly for us to perform hydraulic fracturing.

 

The adoption of derivatives legislation could have an adverse impact on our ability to use derivatives as hedges against fluctuating commodity prices.

 

In July 2010, the Dodd-Frank Act was enacted, representing an extensive overhaul of the framework for regulation of U.S. financial markets. The Dodd-Frank Act called for various regulatory agencies, including the SEC and the Commodities Futures Trading Commission (“CFTC”), to establish regulations for implementation of many of its provisions. The Dodd-Frank Act contains significant derivatives regulations, including requirements that certain transactions be cleared on exchanges and that cash collateral (margin) be posted for such transactions. The Dodd-Frank Act provides for an exemption from the clearing and cash collateral requirements for commercial end-users, such as Carbon, and includes a number of defined terms used in determining how this exemption applies to particular derivative transactions and the parties to those transactions. We have satisfied the requirements for the commercial end-user exception to the clearing requirement and intend to continue to engage in derivative transactions. In December 2015, the CFTC approved final rules on margin requirements that may have an impact on our hedging counterparty and an interim final rule exemption from the margin requirements for certain uncleared swaps with commercial end-users. The final rules did not impose additional requirements on commercial end-users. The ultimate effect of these new rules and any additional regulations is uncertain. New rules and regulations in this area may result in significant increased costs and disclosure obligations as well as decreased liquidity as entities that previously served as hedge counterparties exit the market.

 

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 oil and natural gas producing properties and leases and to find and develop reserves will depend on our ability to evaluate suitable properties and to consummate transactions in a highly competitive environment for acquiring properties. There is substantial competition for investment capital in the industry. Many of our competitors possess financial, technical and personnel resources 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. Other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. We may not be able to compete successfully in the future in acquiring and developing reserves, marketing produced hydrocarbons, attracting and retaining quality personnel and securing necessary 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, 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 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.

 

 

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 direct 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 and may be unable to successfully integrate acquisitions.

 

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

 

	●	recoverable reserves;
	●	future commodity prices and their applicable differentials;
	●	future operating costs and capital expenditures;
	●	potential environmental and other liabilities; and
	●	accuracy of ownership and title

 

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 liabilities. Inspections may not always be performed on every well, and potential environmental issues 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 may acquire properties on an “as is” basis and may not be entitled to contractual indemnification for unidentified environmental liabilities.

 

In the future we may make acquisitions of assets or 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 effectively integrate the acquired assets or 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 savings from consolidation, to successfully integrate the acquired assets or businesses into our existing operations 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.

 

Various proposals have been made recommending the elimination of certain key U.S. federal tax incentives 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 depend on computer and telecommunications systems and failures in our systems or cyber security attacks could significantly disrupt our business operations.

 

We have entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with our business. In addition, we have developed management processes and procedures and other information technologies which incorporate software licensed from third parties. It is possible we could incur interruption from cyber security attacks, computer viruses or malware. We believe that we maintain adequate anti-virus and malware software and controls, however, any interruptions to our arrangements with third parties for our computing and communication infrastructure or any other interruptions to our information systems could lead to data corruption, communication interruption or otherwise significantly disrupt our business.

 

 

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 financial statements.

 

As a public 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. 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, and to develop and expand our quarterly and annual financial statement closing process in order to satisfy such reporting obligations.

 

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 results in higher legal and financial compliance costs as compared to a public company. As we continue to acquire other properties and expand our business we expect these costs to increase.

 

An active, liquid and orderly trading market for our common stock does not exist and 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 is 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 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 listing standards, that we will be able to obtain any such listing. Until our common stock is listed on a national securities exchange, we expect that it will continue to be eligible to be quoted on the OTCQB. An investor may find it difficult to obtain accurate quotations as to the market value of our common stock. If we fail to meet the criteria set forth in SEC regulations, various requirements may be imposed 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 also makes it more difficult for us to raise additional equity capital in the public market.

 

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. Effective March 15, 2017 and pursuant to a reverse stock split, each 20 shares of issued and outstanding common stock became one share of common stock and no fractional shares were issued. As of March 17, 2017, the closing price for our common stock on the OTCQB was $10.62 per share. Despite this, in the future, 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 an offer 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 our business terms 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 capital through the issuance of equity or debt in the future. In that event, the value of the stockholders’ equity in common stock could be reduced. If we need to raise more equity capital from the sale of common stock, institutional or other investors may negotiate terms more favorable than the current prices of the Company’s common stock. 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.

 

Preferred stock could be issued from time to time with 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.

 

The borrowing base under our secured lending facility presently is $23.0 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 such borrowings, if obtainable, may have a higher interest rate, which would increase debt service could negatively impact operating results. 

 

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 business. Management believes that should the controversies be resolved against the Company, none of the current pending proceedings would have a material adverse effect on 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, which has a par value of $0.01 per share. Our common stock is quoted through the OTC Markets (“OTCQB”) under the symbol CRBO. 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. Effective March 15, 2017 and pursuant to a reverse stock split approved by the shareholders and Board of Directors, each 20 shares of issued and outstanding common stock became one share of common stock and no fractional shares were issued. 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 and gives retroactive effect to the reverse stock split for all periods presented. 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
2016		First		$	14.00			$	3.60
		Second		$	6.00			$	5.00
		Third		$	6.40			$	4.00
		Fourth		$	9.40			$	4.00
2015		First		$	14.60			$	11.60
		Second		$	15.00			$	13.00
		Third		$	14.80			$	12.00
		Fourth		$	14.00			$	7.00

 

As of March 17, 2017, the closing price for our common stock on the OTCQB was $10.62 per share.

 

Holders

 

As of March 15, 2017, there were approximately 725 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 to date paid any cash dividends on our common stock. 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 our business. Our Board of Directors do not anticipate paying any cash dividends to holders of our common stock in the foreseeable future.

 

 

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

 

●

The terms of our credit facility with LegacyTexas Bank that prohibit us from paying dividends on our common stock while amounts are owed to LegacyTexas Bank; 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

 

Effective March 15, 2017 and pursuant to a reverse stock split approved by the shareholders and Board of Directors, each 20 shares of issued and outstanding common stock became one share of common stock and no fractional shares were issued. The table below gives retroactive effect to the reverse stock split for all periods presented.

 

The Company has two stock plans, the Carbon 2011 and 2015 Stock Incentive Plans (collectively the “Carbon Plans”). The Carbon Plans were approved by the shareholders of the Company and, in the aggregate, provide for the issuance of 1,130,000 million shares of common stock for participants eligible to receive awards under the Carbon Plans. See Note 9 of the Consolidated Financial Statements for a description of compensation plans adopted without the approval of the shareholders.

 

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, 2016:

 

Equity Compensation Plan Information
				Number of Securities
				Remaining Available
		Number of Securities		for Future Issuance
		to be Issued Upon		Under Equity
		Exercise of		Compensation Plans
		Outstanding Options,		(Excluding Securities
Plan Category		Warrants, and Rights		Reflected in Column (a))
and Description		(a)		(b)
Equity Compensation Plans Approved by Security Holders (1)		296,308		288,295

 

(1)

In 2011 and 2015, the Company’s shareholders approved the adoption of the Carbon Plans under which 1,130,000 shares, in the aggregate, were reserved for issuance. For the years ended December 31, 2016 and 2015, the Company granted 134,500 and 87,000 shares of restricted stock, respectively. As of December 31, 2016, there are approximately 268,000 shares of unvested restricted stock under the Carbon Plans. For each of the years ended December 31, 2016 and 2015, the Company granted 80,000 restricted performance units. As of December 31, 2016, there are approximately 296,000 shares of unvested performance units under the Carbon Plans.

 

Unregistered Sales of Equity Securities

 

All sales of unregistered equity securities that occurred during the period covered by this report, and through December 31, 2016, 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 “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 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, 2016, our proved developed reserves were comprised of 7% oil and 93% natural gas. Our current capital expenditure program is focused on the acquisition of oil and natural gas properties and the development of our oil and coalbed methane reserves. We believe that our drilling inventory and lease position, combined with our low operating expense structure, provides us with a portfolio of opportunities for the development of our oil and natural gas properties. Our growth plan is centered on the following activities:

 

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

 

Our revenue, profitability and future growth rate depend on many factors which are beyond our control, such as economic, political and regulatory developments and competition from other industry participants. Oil and gas prices historically have been volatile and may fluctuate widely in the future. Our financial results are sensitive to fluctuations in oil and natural gas prices. The following table highlights the quarterly average of NYMEX price trends for oil and natural gas prices since the first quarter of 2015:

 

		2015																2016
		Q1				Q2				Q3				Q4				Q1				Q2				Q3				Q4
Oil (Bbl)		$	48.57			$	57.96			$	46.44			$	42.17			$	33.51			$	45.60			$	44.94			$	49.33
Natural Gas (MMBtu)		$	2.99			$	2.61			$	2.74			$	2.17			$	2.06			$	1.98			$	2.93			$	2.98

 

Oil prices have fallen since reaching highs of over $105.00 per barrel in 2014 and dropping below $28.00 per barrel in February 2016. Natural gas prices have also declined from over $4.80 per Mcf in 2014 to below $1.70 per Mcf in March 2016. Although oil and natural gas prices have begun to recover from the lows experienced during the first quarter of 2016, forecasted prices for both oil and natural gas remain low.

 

Lower oil and natural gas prices may not only decrease our revenues, but may also reduce the amount of oil and natural gas that the Company can produce economically and potentially lower our oil and natural gas reserves. The Company’s estimated proved reserves may decrease as the economic life of the underlying producing wells may be shortened as a result of lower oil and natural gas prices. A substantial or extended decline in oil or natural gas prices may result in future impairments of our proved reserves and may materially and adversely affect our future business, financial condition, cash flows, results of operations or liquidity.

 

The Company uses the full cost method of accounting for its oil and gas properties and performs a ceiling test quarterly. Because the ceiling calculation requires a rolling 12 month average commodity price, due to the effect of lower prices in 2016 and 2015, the Company recognized an impairment of approximately $4.3 million and $5.4 million for the years ended December 31, 2016 and 2015, respectively.

 

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

 

Impairment charges do not affect cash flows from operating activities, but do adversely affect net income and stockholders’ equity. An extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, cash flows and liquidity. Lower oil and natural gas prices may also reduce the amount of borrowing base under our bank credit facility, which is determined at the discretion of our lender and also may make it more difficult to comply with the covenants and other restrictions under our bank credit facility.

 

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

 

 

Operational Highlights

 

Weakness in commodity prices during 2015 and 2016 has had a significant adverse impact on our results of operations, our debt balance and the amount of cash flow available to invest in exploration and development activities. Based on current and expected future prices for oil and natural gas during 2016, we reduced our drilling activity to manage and optimize the utilization of our capital resources. During 2016, other than the EXCO Acquisition, our capital expenditures consisted principally of the expansion of our gathering facilities to provide greater flexibility in moving our natural gas production to markets with more favorable pricing.

 

At December 31, 2016, we had approximately 466,000 net acres of mineral leases located in the Appalachian and Illinois Basins of the United States. Approximately 68% of this acreage is held by production and of the remaining acreage, approximately 45% have lease terms of greater than five years remaining in the primary term or contractual extension periods.

 

The principal focus of our leasing, drilling and completion activities is directed at a Berea Sandstone formation horizontal oil drilling program in eastern Kentucky and western West Virginia. As of December 31, 2016, we have over 40,000 net mineral acres in the region. Since 2010, we have drilled 54 horizontal wells in the program. During the program, we have enhanced our well performance, improved well drilling and completion performance, including reduced drilling days, increased horizontal lateral length, decreased cost per frac stage and reduced days from spud to first production. In addition, we have established an infrastructure of oil and natural gas gathering and salt water handling and disposal facilities which will benefit the economics of future drilling. We continue to acquire leases and producing properties where we have identified additional potential to expand our activities.

 

Another area of focus of our drilling and completion activities is the development of a coalbed methane resource located in the Illinois Basin. The Company has approximately 63,000 net mineral acres in Indiana and Illinois which are prospective for the development of coalbed methane. The Company also owns interests in natural gas gathering, compression and salt water disposal facilities. Since 2006, we have conducted a drilling program in the Seelyville coal formation, including participating as a 50% joint venture partner in the drilling of 36 vertical and two horizontal wells. During 2015, the Company participated in the drilling of 25 stratigraphic wells to identify potential future horizontal locations in the Seelyville coal formation.

 

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

 

Recent Developments

 

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

 

Effective March 15, 2017 and pursuant to a reverse stock split approved by the shareholders and Board of Directors, each 20 shares of issued and outstanding common stock became one share of common stock and no fractured shares were issued. All references to the number of shares of common stock and per share amounts give retroactive effect to the reverse stock split for all periods presented.

 

Acquisitions

 

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

 

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

 

●

Approximately 2,300 natural gas wells and over 900 miles of associated natural gas gathering pipelines and compression facilities operated by the Company. As of December 31, 2016, these wells were producing approximately 9,000 net Mcfe per day (97% natural gas).

 

●

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

 

●

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

 

●

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

 

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

 

 

On February 15, 2017, the Company entered into an Amended and Restated Limited Liability Company Agreement (“LLC Agreement”) of Carbon California Company, LLC, a Delaware limited liability company (“Carbon California”) established by the Company. Pursuant to the LLC Agreement, Carbon acquired a 17.813% interest in Carbon California represented by Class B Units and will be the sole manager of Carbon California. The Class B Units were acquired for no cash consideration. In connection with its role as the sole manager of Carbon California, $600,000 of general and administrative expenses will be allocated to and paid by Carbon California. The negotiation and diligence of the oil and gas acquisitions described below was led by the Company and at the closing of the acquisitions, the Company was reimbursed $500,000 for its time and expenditures related to such efforts.

 

On February 15, 2017, Carbon California (i) issued and sold Class A Units to two institutional investors for an aggregate cash consideration of $22 million, (ii) entered into a Note Purchase Agreement (the “Note Purchase Agreement”) with two institutional investors for the issuance and sale of up to $25 million of Senior Secured Revolving Notes (the “Senior Revolving Notes”) due February 15, 2022 and (iii) entered into a Securities Purchase Agreement (the “Securities Purchase Agreement”) with one institutional investor for the issuance and sale of $10 million of Senior Subordinated Notes (the “Subordinated Notes”) due February 15, 2024. The closing of the Note Purchase Agreement and the Securities Purchase Agreement on February 15, 2017, resulted in the sale and issuance by Carbon California LLC of (xi) Senior Revolving notes in the principal amount of $10 million and (xii) Subordinated Notes in the original principal amount of $10 million. The maximum principal amount available under the Senior Revolving Notes is based upon the borrowing base attributable to Carbon California’s proved oil and gas reserves which is to be determined at least semi-annually. The current borrowing base is $15 million.

 

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

 

In connection with the Company entering into the LLC Agreement described above and Carbon California engaging in the transactions also described above, the Company issued to an affiliate of one of the institutional investors which purchased Class A Units of Carbon California (which is also an affiliate of the Company’s largest stockholders), a warrant to purchase shares of the Company’s common stock at an exercise price of $7.20 per share (the “Warrant”). The exercise price for the Warrant is payable exclusively with Class A Units of Carbon California and the number of shares of the Company’s common stock for which the Warrant is exercisable is determined, as of the time of exercise, by dividing (a) the aggregate unreturned capital of the Warrantholder’s Class A Units of Carbon California by (b) the exercise price. The Warrant has a term of seven years and includes certain standard registration rights with respect to the shares of the Company’s common stock issuable upon exercise of the Warrant. If exercised, the Warrant provides the Company an opportunity to increase its ownership stake in Carbon California without requiring the payment of cash. As of the date hereof, the Warrant is exercisable for an aggregate of 1,527,778 shares of the Company’s common stock.

 

Divestitures

 

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

 

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

 

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

 

 

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 market, together with the costs incurred to maintain our producing properties. Such costs include maintenance, repairs and workover expenses related to our oil and natural gas properties.
	●	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 performs 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, 2016 and 2015, the Company incurred ceiling test impairments of approximately $4.3 million and $5.4 million, respectively.

 

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

 

	●	General and administrative expense.  These costs include payroll and benefits for our corporate staff, non-cash stock based compensation, costs of maintaining our offices, costs of managing our production, development and acquisition operations, franchise taxes, audit, tax, legal and other professional fees and legal compliance.
	●	Interest expense.  We finance a portion of our working capital requirements drilling and completion activities 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 typically have not been in a tax paying position for regular federal income taxes, primarily due to the current deductibility of intangible drilling costs (“IDC”) and net operating loss (“NOL”) carryforwards. We pay alternative minimum tax, state income or franchise taxes where IDC or NOL deductions do not exceed taxable income or where state income or franchise taxes are determined on another basis. The Company has net operating losses (“NOL”) of approximately $19.7 million available to reduce future years’ federal tax income. The federal net operating losses expire in 2036. The Company has NOL of approximately $34.4 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 carry forwards.

 

 

Results of Operations

 

The following discussion and analysis relates to items that have affected our results of operations for the years ended December 31, 2016 and 2015. 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)		2016				2015				Change
Revenue:
Natural gas sales		$	7,127			$	5,663				26	%
Oil sales			3,316				5,045				-34	%
Commodity derivative (loss) gain			(2,259	)			852				*
Other income			11				118				-91	%
Total revenues			8,195				11,678				-30	%
Expenses:
Lease operating expenses			3,175				2,910				9	%
Transportation costs			1,645				1,710				-4	%
Production and property taxes			820				887				-8	%
General and administrative			8,645				6,741				28	%
Depreciation, depletion and amortization			1,953				2,607				-25	%
Accretion of asset retirement obligations			176				123				43	%
Impairment of oil and gas properties			4,299				5,419				-21	%
Total expenses			20,713				20,397				2	%
Operating loss		$	(12,518	)		$	(8,719	)			29	%
Other income and (expense):
Interest expense		$	(367	)		$	(201	)			83	%
Investment income			49				16				206	%
Other income (expense)			17				(30	)			*
Total other expense		$	(301	)		$	(215	)			40	%
Production data:
Natural gas (MMcf)			2,823				2,040				38	%
Oil and liquids (MBbl)			79				101				-22	%
Combined (MMcfe)			3,297				2,646				25	%
Average prices before effects of hedges:
Natural gas (per Mcf)		$	2.53			$	2.78				-9	%
Oil and liquids (per Bbl)		$	41.95			$	49.83				-16	%
Combined (per Mcfe)		$	3.17			$	4.04				-22	%
Average prices after effects of hedges**:
Natural gas (per Mcf)		$	1.89			$	3.01				-37	%
Oil and liquids (per Bbl)		$	36.14			$	53.48				-32	%
Combined (per Mcfe)		$	2.48			$	4.37				-43	%
Average costs (per Mcfe):
Lease operating expenses		$	0.96			$	1.10				-13	%
Transportation costs		$	0.50			$	0.65				-23	%
Production and property taxes		$	0.25			$	0.33				-24	%
Depreciation, depletion and amortization		$	0.59			$	0.98				-40	%

 

*   Not meaningful or applicable

** Includes realized and unrealized commodity derivative gains and losses

  

 

Oil and natural gas sales- Revenues from sales of oil and natural gas decreased 2% to approximately $10.4 million for the year ended December 31, 2016 from approximately $10.7 million for the year ended December 31, 2015. Oil revenues for the year ended December 31, 2016 decreased 34% compared to the year ended December 31, 2015, primarily due to a 16% decrease in oil prices and a 22% decrease in oil production. The oil volume decrease between periods was primarily attributable to normal production declines. Natural gas revenues in the year ended December 31, 2016 increased 26% over the same period in 2015 primarily due to an increase in gas production of 38% primarily due to the acquisition of producing oil and natural gas properties in the Appalachian Basin in the fourth quarter of 2016, partially offset by a 9% decrease in natural gas prices.

 

Commodity derivative (losses) gains - To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we enter into derivative contracts using fixed price swap contracts and costless collars when our management believes that available futures prices for our oil and natural gas production are sufficient to warrant hedging to ensure predictable cash flows for a portion 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, as well as realized gains or losses on the derivative instruments, are currently recognized in our results of operations. The unrealized gains and losses represent the changes in the fair value of these contracts as oil and natural gas futures prices fluctuate relative to the fixed price we will receive from these contracts. For the years ended December 31, 2016 and 2015, we had commodity derivative losses of approximately $2.3 million and gains of approximately $852,000, respectively. On September 30, 2016, in connection with the termination and payoff of the Company’s credit facility with the Bank of Oklahoma, the Company closed all of its commodity derivative instruments in which Bank of Oklahoma was the counterparty.

 

Lease operating expenses- Lease operating expenses for the year ended December 31, 2016 increased 9% compared to the year ended December 31, 2015. This increase is principally attributed to the acquisition of producing oil and natural gas properties in the Appalachian Basin in the fourth quarter of 2016. On a per Mcfe basis, lease operating expenses decreased from $1.10 per Mcfe for the year ended December 31, 2015 to $0.96 per Mcfe for the year ended December 31, 2016. This decrease was primarily attributed to cost reduction measures implemented by the Company and lower water hauling and salt water disposal fees as a result of lower oil production.

 

Transportation costs- Transportation costs decreased 4% from the year ended December 31, 2015 to the year ended December 31, 2016, primarily attributed to the expiration of a higher priced firm transportation contract that expired in the fourth quarter of 2015 partially offset by transportation costs for the Appalachian Basin properties acquired in the fourth quarter of 2016. On a per Mcfe basis, transportation costs decreased from $0.65 per Mcfe for the year ended December 31, 2015 to $0.50 per Mcfe for the year ended December 31, 2016 primarily due to the expiration of the firm transportation contract mentioned above and lower average transportation costs for the Appalachian Basin properties acquired in the fourth quarter of 2016.

 

Production and property taxes- Production and property taxes decreased 8% from approximately $887,000 for the year ended December 31, 2015 to approximately $820,000 for the year ended December 31, 2016. This decrease is primarily attributed to the termination, effective July 1, 2016, of additional severance tax assessed on natural gas revenues in West Virginia and a reserve established by the Company in the third quarter of 2015 for potential additional production taxes on certain of its wells in Kentucky due to a court ruling. This decrease was partially offset by an increase in production taxes associated with the Company’s acquisition of producing oil and natural gas properties in the Appalachian Basin in the fourth quarter of 2016. Production taxes are generally calculated as a percentage of sales revenue, which averages approximately 4.1% 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 oil and natural gas revenues one or two years in arrears depending upon the location of the production.

 

Depreciation, depletion and amortization (DD&A)- DD&A decreased from approximately $2.6 million for the year ended December 31, 2015 to approximately $2.0 million for the year ended December 31, 2016 primarily due to a reduction in the Company’s depletion rate. The decrease in the depletion rate is primarily attributable to the acquisition of producing oil and natural gas properties in the Appalachian Basin in the fourth quarter of 2016 which reduced the Company’s blended depletion rate. In addition, the depletion rate decreased due to impairment changes recognized by the Company during the first six months of 2016. On a per Mcfe basis, DD&A decreased from $0.98 per Mcfe for the year ended December 31, 2015 to $0.59 per Mcfe for the year ended December 31, 2016.

 

Impairment of oil and gas properties- Due to low commodity prices used in the ceiling calculation, the Company recorded impairment expenses of approximately $4.3 million during the first two quarters of 2016 in addition to recording an impairment expense of approximately $5.4 million for the fourth quarter of 2015. The ceiling limitation calculation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet. Any recorded impairment is not reversible at a later date.

 

 

General and administrative expenses- Cash-based general and administrative expenses increased from approximately $5.3 million for the year ended December 31, 2015 to approximately $6.2 million for the year ended December 31, 2016. The increase was primarily attributed personnel related and third party costs associated with the EXCO Acquisition and other potential acquisition opportunities. Non-cash based compensation increased from approximately $1.4 million for the year ended December 31, 2015 to approximately $2.4 million for the year ended December 31, 2016. During 2016, the Company estimated that it was probable that certain of the performance units granted in 2014 and 2015 would vest and compensation costs of approximately $1.2 million related to those performance units were recognized for the year ended December 31, 2016. Non-cash stock based compensation and other general and administrative expenses for the years ended December 31, 2016 and 2015 are summarized in the following table:

 

		Year Ended December 31,								Increase/
		2016				2015				(Decrease)
General and administrative expenses
(in thousands)
Stock-based compensation		$	2,440			$	1,443			$	997
Other general and administrative expenses			6,205				5,298				907
Total general and administrative expenses		$	8,645			$	6,741			$	1,904

  

Interest expense- Interest expense increased from approximately $201,000 for the year ended December 31, 2015 to approximately $367,000 for the year ended December 31, 2016 primarily due to an increase in average effective interest rates and higher average outstanding debt during 2016 as compared to 2015. In October 2016, the Company increased its outstanding debt by approximately $9.5 million to fund the EXCO Acquisition and for other working capital needs of the Company.

 

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 the sale of assets.

 

Changes in the market prices for oil and natural gas directly impact our level of cash flow generated from operations. The prices we receive for our production are determined by prevailing market conditions and greatly influence our revenue, cash flow, profitability, access to capital and future rate of growth. We employ a commodity hedging strategy in an attempt to moderate the effects of commodity price fluctuations on our cash flow.

 

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

 

The following table reflects the Company’s outstanding derivative hedges as of December 31, 2016:

 

		Natural Gas								Oil
						Weighted								Weighted
						Average Price								Average Price
Year		MMBtu				(a)				Bbl				(b)
2017			3,360,000			$	3.30				60,000			$	52.98
2018			3,120,000			$	3.01				48,000			$	54.11
2019			1,320,000			$	2.85				36,000			$	54.90

 

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

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

 

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

 

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

 

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

 

 

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

 

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

 

In February 2017, the Company entered into a limited liability agreement of Carbon Appalachian Company, LLC (“CAC”). CAC is currently actively engaged in negotiating a transaction to acquire oil and gas interests and related facilities in the Appalachia Basin and expects to pursue future complementary acquisitions. The Company expects that in its role as manager of CAC, it will have additional administrative responsibilities but will be able to allocate a portion of its general and administrative expense to CAC.

 

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

 

Bank Credit Facility

 

On September 30, 2016, the Company terminated its credit facility with Bank of Oklahoma. On October 3, 2016, in connection with and concurrently with the closing of the EXCO Acquisition, Carbon entered into a 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank. LegacyTexas Bank is the initial lender and acts as administrative agent.

 

The credit facility has a maximum availability of $100.0 million (with a $0.5 million sublimit for letters of credit), which availability is subject to the amount of the borrowing base. The borrowing base under the credit facility is $17.0 million. The borrowing base is subject to semi-annual redeterminations in March and September commencing March 2017. On March 30, 2017, the borrowing base was increased to $23.0 million. 

 

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

 

Interest is payable quarterly and accrues on borrowings under the credit facility at a rate per annum equal to either (i) the base rate plus an applicable margin between 0.50% and 1.50% or (ii) the Adjusted LIBOR rate plus an applicable margin between 3.50% and 4.50% at Carbon’s option. The actual margin percentage is dependent on the credit facility utilization percentage. Carbon is obligated to pay certain fees and expenses in connection with the credit facility, including a commitment fee for any unused amounts of 0.50%. The Company also paid an origination fee of .75% upon closing the credit facility.

 

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

 

The affirmative and negative covenants are subject to various exceptions, including certain basket amounts and acceptable transaction levels. In addition, the credit facility requires Carbon’s compliance, on a consolidated basis, with (i) a maximum funded Debt/EBITDA ratio of 3.5 to 1.0 and (ii) a minimum current ratio of 1.0 to 1.0, commencing with the quarter ended March 31, 2017.

 

 

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

 

As required under the terms of the credit facility, the Company has agreed to establish pricing for a certain percentage of its production through the use of derivative contracts. To that end, the Company entered into an ISDA Master Agreement with BP Energy Company that established standard terms for the derivative contracts and an inter-creditor agreement with Legacy Texas Bank and BP Energy Company whereby any credit exposure related to the derivative contracts entered into by the Company and BP Energy Company is secured by the collateral and backed by the guarantees supporting the credit facility.

 

Initial borrowings under the credit facility were used (1) to pay off and terminate Nytis LLC’s existing credit facility with Bank of Oklahoma, (ii) to pay the purchase price of the EXCO Acquisition, (iii) to pay costs and expenses associated with the EXCO Acquisition and (iv) to provide working capital for the Company. As of December 31, 2016, there was approximately $16.2 million in borrowings under the credit facility. The Company’s effective borrowing rate as of December 31, 2016 was approximately 5.4%.

 

Sources and Uses of Cash

 

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

 

The significant decline in year-over-year prices for our oil and natural gas production adversely impacted our operating cash flow for 2016 and consequently reduced the amount of cash available for development activities.

 

The following table presents net cash provided by or used in operating, investing and financing activities for the years ended December 31, 2016 and 2015.

 

		Years Ended
		December 31,
(in thousands)		2016				2015
Net cash (used in) provided by operating activities		$	(3,142	)		$	509
Net cash used in investing activities		$	(8,754	)		$	(2,435	)
Net cash provided by financing activities		$	12,449			$	1,099

  

Net cash used in or provided by operating activities is primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and changes in working capital. Operating cash flows were approximately $3.7 million lower for the year ended December 31, 2016 as compared to the same period in 2015. This decrease was primarily due to a decrease in cash settlements received on our derivative contracts, an increase in working capital during 2016 and lower oil revenues, partially offset by higher natural gas revenues.

 

Net cash used in investing activities is primarily comprised of the acquisition, exploration, and development of oil and natural gas properties, net of dispositions of oil and natural gas properties. Net cash used in investing activities increased approximately $6.3 million for the year ended December 31, 2016 as compared to the year ended December 31, 2015. This increase is principally associated with the purchase of oil and natural gas properties in the Appalachian Basin in the fourth quarter of 2016, partially offset by a decrease in drilling and development expenditures. Due to continued low oil and natural gas prices, the Company continued to reduce its drilling and development programs in 2016.

 

The increase in financing cash flows of approximately $11.4 million for the year ended December 31, 2016 as compared to the year ended December 31, 2015 was primarily due to borrowings used to fund the purchase of Appalachian Basin producing properties and payoff the Company’s former credit facility.

 

 

Capital Expenditures

 

Capital expenditures for the years ended December 31, 2016 and 2015 are summarized in the following table:

 

		Years Ended December 31,
(in thousands)		2016				2015
Acquisition of oil and gas properties:
Unevaluated properties		$	97			$	341
Oil and natural gas producing properties			8,117				-
Drilling and development			360				2,106
Pipeline and gathering			42				578
Other			201				87
Total capital expenditures		$	8,817			$	3,112

 

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

 

In the fourth quarter of 2016, the Company acquired producing oil and natural gas properties located principally in West Virginia. Due to continued low commodity prices, the Company has significantly reduced its drilling programs in 2015 and 2016 and focused on expanding its gathering facilities to provide greater flexibility in moving natural gas production to markets with more favorable pricing. Other factors impacting the level of our capital expenditures include the cost and availability of oil field services, general economic and market conditions, and weather disruptions.

 

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, 2016, 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, 2016 and 2015 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 3 to the Consolidated Financial Statements for a more complete discussion of the rule and our estimated proved reserves as of December 31, 2016 and 2015.

 

 

Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a quarterly 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. Such impairments are permanent and cannot be recovered even if the sum of the components noted above exceeds capitalized costs in future periods. 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. In the first and second quarters of 2016 and the fourth quarter of 2015, the carrying value of our oil and gas properties subject to the ceiling test exceeded the calculated value of the ceiling limitation, and we recognized an impairment of approximately $4.3 million and $5.4 million for the years ended December 31, 2016 and 2015, respectively. These impairments resulted primarily from the impact of a decrease in the 12-month average trailing price for oil and natural gas utilized in determining the future net cash flows from proved reserves. 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 additional impairments of our oil and natural gas properties in future periods.

 

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. Subject to industry conditions, evaluation of most of our unproved properties and inclusion of these costs in proved property costs subject to amortization are expected to be completed within five years.

 

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 gain or loss in our Consolidated Statements of Operations.

 

 

As of December 31, 2016 and 2015, the fair value of the Company’s derivative agreements was a liability of approximately $1.9 million and an asset of approximately $559,000, respectively. The fair value measurement of 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 11 to the Consolidated Financial Statements for further discussion. The values we report in our financial statements are as of a point in 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, 2016 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 book income in 2013 and 2014, forecasted book income if commodity prices increase, and taxable proceeds from the Liberty participation agreements and the sale of the Company’s Deep Rights in leases in Kentucky and West Virginia in 2014. 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 and current commodity prices which will impact forecasted income or loss.

 

As of December 31, 2016 and 2015, 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 more-likely-than-not that the deferred tax assets will not be realized in the near future. Based on this assessment, the Company recorded a full valuation allowance of approximately $21.1 million and $16.7 million on its deferred tax assets as of December 31, 2016 and 2015, 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.

 

Purchase Price Allocation

 

Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities acquired based on their estimated fair value as of the acquisition date. Various assumptions are made when estimating fair values assigned to proved and unproved oil and gas properties including: (i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) future cash flows; and (vi) a market participant-based weighted average cost of capital rate. These inputs require significant judgement by management at the time of the valuation.

 

Revenue Recognition

 

Oil and natural gas revenues are recognized when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability is reasonably assured. Natural gas revenues are recognized on the basis of the Company’s net working revenue interest. Net deliveries in excess of entitled amounts are recorded as a liability, while net deliveries lower than entitled amounts are recorded as a receivable.

 

 

Non-GAAP Measures

 

EBITDA and Adjusted EBITDA

 

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

 

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

 

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

 

 

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, 2016 and 2015.

 

		For the Year Ended
		December 31,
(in thousands)		2016				2015
Net loss		$	(12,819	)		$	(8,934	)
Adjustments:
Interest expense			367				201
Depreciation, depletion and amortization			1,953				2,607
Income taxes			-				-
EBITDA			(10,499	)			(6,126	)
Adjusted EBITDA
EBITDA			(10,499	)			(6,126	)
Adjustments:
Accretion of asset retirement obligations			176				123
Impairment of oil and gas properties			4,299				5,419
Non-cash stock compensation			2,440				1,443
Adjusted EBITDA		$	(3,584	)		$	859

 

PV-10

 

PV-10 is a non-GAAP financial measure. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and gas properties. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with US GAAP, but rather should be considered in addition to the standardized measure.

 

PV-10 is derived from the standardized measure, which is the most directly comparable GAAP financial measure. PV-10 is calculated using the same inputs and assumptions as the standardized measure, with the exception that it omits the impact of future income taxes. It is considered to be a pre-tax measurement.

 

The following table provides a reconciliation of the standardized measure to PV-10 at December 31, 2016 and 2015 (in thousands):

 

		As of December 31,
		2016				2015
Standardized measure of discounted future net cash flows		$	44,711			$	25,032
Add: 10 percent annual discount, net of income taxes			51,522				30,172
Add: future undiscounted income taxes			14,858				-
Future pre-tax net cash flows		$	111,091			$	55,204
Less: 10 percent annual discount, pre-tax			(61,747	)			(30,172	)
PV-10		$	49,344			$	25,032

  

 

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

Denver, Colorado

 

We have audited the accompanying consolidated balance sheets of Carbon Natural Gas Company and subsidiaries (the”Company”) as of December 31, 2016 and 2015, 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 consolidated 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, 2016 and 2015, 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, 2017

 

 

CARBON NATURAL GAS COMPANY

Consolidated Balance Sheets

(In thousands)

 

		December 31,				December 31,
		2016				2015
ASSETS
Current assets:
Cash and cash equivalents		$	858			$	305
Accounts receivable:
Revenue			2,369				1,082
Joint interest billings and other			2,251				778
Commodity derivative asset			-				408
Prepaid expense and deposits			305				213
Total current assets			5,783				2,786
Property and equipment (note 5)
Oil and gas properties, full cost method of accounting:
Proved, net			33,212				25,032
Unproved			1,999				3,194
Other property and equipment, net			325				238
			35,536				28,464
Investments in affiliates (note 6)			668				1,025
Other long-term assets			725				433
Total assets		$	42,712			$	32,708
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities		$	9,121			$	5,621
Commodity derivative liability			1,341				-
Firm transportation contract obligations (note 13)			561				436
Total current liabilities			11,023				6,057
Non-current liabilities:
Firm transportation contract obligations (note 13)			261				416
Commodity derivative liability			591				-
Ad valorem taxes payable			628				-
Asset retirement obligations (note 3)			5,006				3,095
Notes payable (note 7)			16,230				3,500
Total non-current liabilities			22,716				7,011
Commitments and contingencies (note 13)
Stockholders’ equity:
Preferred stock, $0.01 par value; authorized 1,000,000 shares, no shares issued and outstanding at December 31, 2016 and 2015			-				-
Common stock, $0.01 par value; authorized 200,000,000 shares, 5,482,673 and 5,382,796 shares issued and outstanding at December 31, 2016 and 2015, respectively			1,096				1,077
Additional paid-in capital			56,548				54,394
Accumulated deficit			(50,536	)			(38,130	)
Total Carbon stockholders’ equity			7,108				17,341
Non-controlling interests			1,865				2,299
Total stockholders’ equity			8,973				19,640
Total liabilities and stockholders’ equity		$	42,712			$	32,708

 

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,
		2016				2015
Revenue:
Natural gas sales		$	7,127			$	5,663
Oil sales			3,316				5,045
Commodity derivative (loss) gain			(2,259	)			852
Other income			11				118
Total revenue			8,195				11,678
Expenses:
Lease operating expenses			3,175				2,910
Transportation costs			1,645				1,710
Production and property taxes			820				887
General and administrative			8,645				6,741
Depreciation, depletion and amortization			1,953				2,607
Accretion of asset retirement obligations			176				123
Impairment of oil and gas properties			4,299				5,419
Total expenses			20,713				20,397
Operating loss			(12,518	)			(8,719	)
Other income and (expense):
Interest expense			(367	)			(201	)
Investment income			49				16
Other income (expense)			17				(30	)
Total other expense			(301	)			(215	)
Loss before income taxes			(12,819	)			(8,934	)
Income tax expense:
Current			-				-
Net loss			(12,819	)			(8,934	)
Net loss attributable to non-controlling interests			413				636
Net loss attributable to controlling interest		$	(12,406	)		$	(8,298	)
Net loss per common share:
Basic		$	(2.27	)		$	(1.56	)
Diluted		$	(2.27	)		$	(1.56	)
Weighted average common shares outstanding (in thousands):
Basic			5,468				5,335
Diluted			5,468				5,335

 

See accompanying notes to Consolidated Financial Statements.

 

 

CARBON NATURAL GAS COMPANY

Consolidated Statements of Stockholders’ Equity

(In thousands)

 

										Additional				Non-								Total
		Common Stock								Paid-in				Controlling				Accumulated				Stockholders’
		Shares				Amount				Capital				Interests				Deficit				Equity
Balances, December 31, 2014			5,344			$	1,069			$	53,160			$	3,035			$	(29,832	)		$	27,432
Stock-based compensation			-				-				1,443				-				-				1,443
Restricted stock activity including vesting and shares exchanged for tax withholding			39				8				(209	)			-				-				(201	)
Non-controlling interests distributions, net			-				-				-				(100	)			-				(100	)
Net loss			-				-				-				(636	)			(8,298	)			(8,934	)
Balances, December 31, 2015			5,383			$	1,077			$	54,394			$	2,299			$	(38,130	)		$	19,640
Stock-based compensation			-				-				2,440				-				-				2,440
Restricted stock vested			65				13				(13	)			-				-				-
Performance units vested			84				17				(17	)			-				-				-
Restricted stock and performance units exchanged for tax withholding			(50	)			(11	)			(256	)			-				-				(267	)
Non-controlling interests distributions, net			-				-				-				(14	)			-				(14	)
Non-controlling interest purchase			-				-				-				(7	)			-				(7	)
Net loss			-				-				-				(413	)			(12,406	)			(12,819	)
Balances, December 31, 2016			5,482			$	1,096			$	56,548			$	1,865			$	(50,536	)		$	8,973

 

See accompanying notes to Consolidated Financial Statements.

 

 

CARBON NATURAL GAS COMPANY

Consolidated Statements of Cash Flows

(In thousands)

 

		Twelve months ended December 31,
		2016				2015
Cash flows from operating activities:
Net loss		$	(12,819	)		$	(8,934	)
Items not involving cash:
Depreciation, depletion and amortization			1,953				2,607
Accretion of asset retirement obligations			176				123
Impairment of oil and gas properties			4,299				5,419
Unrealized derivative loss			2,490				763
Stock-based compensation expense			2,440				1,443
Equity investment loss (income)			17				(16	)
Other			(47	)			(12	)
Net change in:
Accounts receivable			(2,925	)			1,631
Prepaid expenses, deposits and other current assets			(93	)			(72	)
Accounts payable, accrued liabilities and firm transportation contracts			1,367				(2,443	)
Net cash (used in) provided by operating activities			(3,142	)			509
Cash flows from investing activities:
Development of oil and gas properties and other capital expenditures			(700	)			(3,112	)
Acquisition of oil and gas properties			(8,117	)			-
Proceeds from sale of other fixed assets			8				213
Equity investment distributions			340				-
Other long-term assets			(285	)			464
Net cash used in investing activities			(8,754	)			(2,435	)
Cash flows from financing activities:
Vested restricted stock exchanged for tax withholding			(267	)			(201	)
Proceeds from notes payable			16,937				2,000
Payments on notes payable			(4,207	)			(600	)
Distribution to non-controlling interests			(14	)			(100	)
Net cash provided by financing activities			12,449				1,099
Net increase (decrease) in cash and cash equivalents			553				(827	)
Cash and cash equivalents, beginning of period			305				1,132
Cash and cash equivalents, end of period		$	858			$	305

 

See Note 15 – 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 – Reverse Stock Split

 

Effective March 15, 2017 and pursuant to a reverse stock split approved by the shareholders and Board of Directors, each 20 shares of issued and outstanding common stock became one share of common stock and no fractional shares were issued. The accompanying financial statements and related disclosures give retroactive effect to the reverse stock split for all periods presented.

 

Note 3 – 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 and 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 the Company’s 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, if any, 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 receivable are primarily comprised of oil and natural gas revenues from producing activities 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, 2016 and 2015, 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. In addition, accounts receivable included a deposit of $1.7 million made by the Company on the purchase of assets in the Ventura Basin of California through Carbon California Company, LLC (“Carbon California”). The deposit was reimbursed to the Company upon the consummation of the acquisition by Carbon California Company LLC on February 15, 2017. See Note 16 for additional information.

 

 

Note 3 – Summary of Significant Accounting Policies (continued)

 

Oil and Natural Gas Sales

 

The Company sells its oil and natural gas production to various purchasers in the industry. The table below presents purchasers that account for 10% or more of total oil and natural gas sales for the years ended December 31, 2016 and 2015. 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		2016				2015
Purchaser A			18	%			18	%
Purchaser B			17	%			24	%
Purchaser C			16	%			15	%
Purchaser D			15	%			15	%

 

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, 2016 and 2015, the Company had a purchaser imbalance payable of approximately $25,000 and a receivable of approximately $270,000, respectively, which are recognized as a current liability and current asset, respectively, in the Company’s Consolidated Balance Sheets.

 

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 4 regarding the Company’s 2015 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 on a quarterly basis. 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, 2016 and 2015, the Company recognized a ceiling test impairment of approximately $4.3 million and $5.4 million, respectively. Future declines in oil and natural gas prices could result in impairments of our oil and gas properties in future periods. Because the ceiling test used previous twelve month period average commodity prices, the effect of declining prices since mid-2014 had a negative impact on the average price used to value our reserves which will lower the ceiling test value in future periods and may result in additional impairments of our oil and gas properties. The effect of price declines will impact the ceiling test value until such time commodity prices stabilize or improve. Impairment changes are a non-cash charge and accordingly would not affect cash flows but would adversely affect our net income and shareholders’ equity.

  

Note 3 – 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 is calculated over three to seven years using the straight-line method.

 

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.

 

 

Note 3 – Summary of Significant Accounting Policies (continued)

 

The following table is a reconciliation of the ARO for the years ended December 31, 2016 and 2015.

 

		Year Ended December 31,
(in thousands)		2016				2015
Balance at beginning of year		$	3,095			$	2,968
Accretion expense			176				123
Additions during period			1,849				4
			5,120				3,095
Less: ARO recognized as a current liability			(114	)			-
Balance at end of year		$	5,006			$	3,095

 

For the year ended December 31, 2016, the addition of approximately $1.8 million to ARO is primarily due to the acquisition of producing oil and natural gas properties in the Appalachian Basin in the fourth quarter of 2016.

 

Financial Instruments

 

The Company’s financial instruments include cash and cash equivalents, accounts receivables, accounts payables, accrued liabilities, commodity derivative instruments and its notes payable. 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 commodity derivative instruments are recorded at fair value, as discussed below and in Note 11. The carrying amount of the Company’s notes payable 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 reduce our exposure to downward price fluctuations. Commodity derivative contracts may take the form of futures contracts, swaps, collars 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

 

Oil and natural gas revenues are recognized when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability is reasonably assured. Natural gas revenues are recognized on the basis of the Company’s net working revenue interest. Net deliveries in excess of entitled amounts are recorded as a liability, while net deliveries lower than entitled amounts are recorded as a receivable.

 

 

Note 3 – Summary of Significant Accounting Policies (continued)

 

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 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 options and warrants to acquire common stock computed using the treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company with the proceeds from the exercise of options and warrants (which were assumed to have been made at the average market price of the common shares during the reporting period).

 

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

 

		For the Year Ended December 31,
(in thousands except per share amounts)		2016				2015
Net loss		$	(12,406	)		$	(8,298	)
Basic weighted-average common shares outstanding during the period			5,468				5,335
Add dilutive effects of stock options, warrants and non-vested shares of restricted stock			-				-
Diluted weighted-average common shares outstanding during the period			5,468				5,335
Basic net (loss) income per common share		$	(2.27	)		$	(1.56	)
Diluted net (loss) income per common share		$	(2.27	)		$	(1.56	)

 

For the year ended December 31, 2016, the Company had a net loss and therefore the diluted loss per common share calculation excludes the anti-dilutive effects of approximately 13,000 warrants and approximately 268,000 non-vested shares of restricted stock. In addition, approximately 296,000 restricted performance units subject to future contingencies were excluded from the basic and diluted loss per share calculations. For the year ended December 31, 2015, the Company had a net loss and therefore the loss per common share calculation excludes the anti-dilutive effects of approximately 8,000 stock options, 13,000 warrants and 248,000 non-vested shares of restricted stock. In addition, approximately 314,000 restricted performance units subject to future contingencies were excluded from the basic and diluted loss per share calculation.

 

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 commodity derivative instruments, fair value of assets acquired qualifying as business contributions and asset retirement obligations. Actual results could differ from those estimates and assumptions used.

 

Adopted and Recently Issued Accounting Pronouncements

 

In August 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-15, Statement of Cash Flows-Classification of Certain Cash Receipts and Cash Payments. The objective of this update is intended to reduce the diversity in practice as to how certain cash receipts and cash payments are presented and classified in the statement of cash flows by providing guidance for several specific cash flow issues. ASU 2016-15 is effective for the annual periods beginning after December 15, 2017, and interim periods within those annual periods. The Company is currently evaluating the impact of adopting this standard.

 

In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes. The objective of this update is to require deferred tax liabilities and assets to be classified as noncurrent in a classified statement of financial position. ASU 2015-17 is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The standard will be adopted retrospectively, effective January 1, 2017, and will not have a significant impact on the Company's disclosures and financial statements.

  

  

Note 3 – Summary of Significant Accounting Policies (continued)

 

In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. The objective of this update requires an entity’s management to evaluate, for each reporting period, including interim periods, of whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued. Additional disclosures are required if management concludes that conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The new guidance was effective for the Company in the fourth quarter of 2016. The Company adopted the standard for this annual report ending December 31, 2016 and it did not have a significant impact on the Company’s disclosures and financial statements.

 

In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805). This ASU clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This guidance is to be applied using a prospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted as outlined in ASU 2017-01. The Company is currently evaluating the provisions of this guidance and assessing its potential impact on the Company’s financial statements and disclosures.

 

In September 2015, the FASB issued ASU 2015-16, Business Combinations (Topic 805). This ASU simplifies the accounting for measurement period adjustments by eliminating the requirements to restate prior period financial statements for these adjustments. The new guidance requires that the cumulative impact of a measurement period adjustment (including the impact on prior periods) be recognized in the reporting period in which the adjustment is identified. The new standard, which should be applied prospectively to measurement period adjustments that occur after the effective date, was effective for the Company in the first quarter of 2016. The adoption of the new accounting rules did not have a material impact on the Company’s financial condition, results of operations or cash flows.

 

Note 4 – Acquisitions and Divestitures

 

Acquisitions

 

On October 3, 2016 (the “Closing Date”), Nytis LLC completed an acquisition (the “EXCO Acquisition”) consisting of producing natural gas wells and natural gas gathering facilities located in the Company’s Appalachian Basin operating area. The natural gas gathering facilities are primarily used to gather the Company’s natural gas production. The acquisition was pursuant to a purchase and sale agreement effective October 1, 2016 (the “EXCO Purchase Agreement”) by and among EXCO Production Company (WV), LLC, BG Production Company (WV), LLC and EXCO Resources (PA) LLC (collectively the “Sellers”) and Nytis LLC, as the buyer. The purchase price of the acquired assets pursuant to the EXCO Purchase Agreement was $9.0 million subject to customary closing adjustments and the assumption of certain obligations.

 

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

 

The EXCO Acquisition qualified as a business combination and as such, the Company estimated the fair value as of the Closing Date of the assets acquired and liabilities assumed as of the Closing Date. The Company considered various factors in its estimate of fair value of the acquired assets including (i) reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices, including price differentials, (v) future cash flows, and (vi) a market participant-based weighted average cost of capital.

 

The Company expensed approximately $501,000 of transaction and due diligence costs related to the EXCO Acquisition that were included in general and administrative expenses in the accompanying Consolidated Statement of Operations for the year ended December 31, 2016.

 

The following table summarizes the preliminary consideration paid to the Sellers and the estimated fair value of the assets acquired and liabilities assumed.

 

Consideration paid to Sellers:
Cash consideration		$	8,117
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved oil and gas properties and related support facilities		$	12,656
Asset retirement obligations			(1,845	)
Working capital			(2,694	)
Total identified net assets		$	8,117

 

The estimated fair value of the asset acquired and liabilities assumed will be adjusted to reflect any changes in the consideration paid pursuant to the final closing statement.

 

 

Note 4 – Acquisitions and Divestitures (continued)

 

The EXCO Acquisition was funded through borrowings from the Company’s credit facility with LegacyTexas Bank.

 

EXCO Acquisition Unaudited Pro Forma Results of Operations

 

Below are consolidated results of operations for the years ended December 31, 2016 and 2015 as though the EXCO Acquisition made during 2016 had been completed as of January 1, 2015. The EXCO Acquisition closed October 3, 2016, and accordingly, the Company’s consolidated statements of operations for the year ended December 31, 2016 includes the results of operations for the three months ended December 31, 2016 of the EXCO properties acquired, including approximately $2.4 million of revenue.

 

		Unaudited Pro Forma Consolidated Results
		For Years Ended December 31,
(in thousands, except per share amounts )			2016				2015
Revenue		$	13,963			$	22,178
Net (loss) income before non-controlling interests			(6,825	)			(3,627	)
Net loss (income) attributable to non-controlling interests			413				636
Net (loss) income attributable to controlling interests			(6,412	)			(2,991	)
Net (loss) income per share (basic)			(1.17	)			(0.56	)
Net (loss) income per share (diluted)			(1.17	)			(0.56	)

 

Divestitures

 

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

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

During 2015, the final closing was completed. In connection with the final closing, Nytis LLC received an additional $42,000 in cash.

Note 5 – Property and Equipment

 

Net property and equipment at December 31, 2016 and 2015 consists of the following:

 

(in thousands)		As of December 31,
		2016				2015
Oil and gas properties:
Proved oil and gas properties		$	111,771			$	97,453
Unproved properties not subject to depletion			1,999				3,194
Accumulated depreciation, depletion, amortization and impairment			(78,559	)			(72,421	)
Net oil and gas properties			35,211				28,226
Furniture and fixtures, computer hardware and software, and other equipment			990				825
Accumulated depreciation and amortization			(665	)			(587	)
Net other property and equipment			325				238
Total net property and equipment		$	35,536			$	28,464

 

The Company had approximately $2.0 million and $3.2 million, at December 31, 2016 and 2015, respectively, of unproved oil and gas properties not subject to depletion. At December 31, 2016 and 2015, the Company’s unproved properties consist principally of leasehold acquisition costs in the following areas: 

		As of December 31,
(in thousands)		2016				2015
Illinois Basin:
Indiana		$	431			$	433
Illinois			298				309
Appalachian Basin:
Kentucky			750				1,523
Ohio			66				66
West Virginia			454				863
Total unproved properties not subject to depletion		$	1,999			$	3,194

 

Note 5 – Property and Equipment (continued)

 

During the years ended December 31, 2016 and 2015, expiring leasehold costs reclassified into proved property were approximately $1.3 million and $189,000, 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.

 

The Company capitalized overhead applicable to acquisition, development and exploration activities of approximately $562,000 and $576,000 for the years ended December 31, 2016 and 2015, respectively.

 

Depletion expense related to oil and gas properties for the years ended December 31, 2016 and 2015 was approximately $1.8 million and $2.5 million or $0.56 and $0.93 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, 2016 and 2015 was approximately $114,000 and $140,000, respectively.

 

Note 6 – Equity and Cost Method Investment

 

The Company has a 50% interest in Crawford County Gas Gathering Company, LLC (“CCGGC”) which owns and operates pipelines and related gathering and treating facilities. The Company’s gas production located in Illinois is gathered and transported on CCGGC’s gathering facilities. The Company’s investment in CCGGC is accounted for under the equity method of accounting, and its share of the income or loss is recognized. For the years ended December 31, 2016 and 2015, the Company recorded equity method loss of approximately $17,000 and income of approximately $16,000, respectively, related to this investment. In addition, during 2016, the Company received cash distributions totaling $340,000 from CCGGC.

 

During 2016, the Company received distributions of approximately $65,000 from its investment in Sullivan Energy which it accounts for using the cost method of accounting and as such the Company recognized investment income of $65,000 for the year ended December 31, 2016.

 

Note 7 – Bank Credit Facility

 

On September 30, 2016, the Company terminated its credit facility with Bank of Oklahoma. On October 3, 2016, in connection with and concurrently with the closing of the EXCO Acquisition, Carbon entered into a 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank. LegacyTexas Bank is the initial lender and acts as administrative agent.

 

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

 

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

 

Interest is payable quarterly and accrues on borrowings under the credit facility at a rate per annum equal to either (i) the base rate plus an applicable margin between 0.50% and 1.50% or (ii) the Adjusted LIBOR rate plus an applicable margin between 3.50% and 4.50% at Carbon’s option. The actual margin percentage is dependent on the credit facility utilization percentage. Carbon is obligated to pay certain fees and expenses in connection with the credit facility, including a commitment fee for any unused amounts of 0.50% and an origination fee of 0.75%.

 

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

 

The affirmative and negative covenants are subject to various exceptions, including certain basket amounts and acceptable transaction levels. In addition, the credit facility requires Carbon’s compliance, on a consolidated basis, with (i) a maximum funded Debt/EBITDA ratio of 3.5 to 1.0 and (ii) a minimum current ratio of 1.0 to 1.0, commencing with the quarter ending March 31, 2017.

 

 

Note 7 – Bank Credit Facility (continued)

 

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

 

As required under the terms of the credit facility, the Company has agreed to establish pricing for a certain percentage of its production through the use of derivative contracts. To that end, the Company has entered into an ISDA Master Agreement with BP Energy Company that establishes standard terms for the derivative contracts and an inter-creditor agreement with LegacyTexas Bank and BP Energy Company whereby any credit exposure related to the derivative contracts entered into by the Company and BP Energy Company is secured by the collateral and backed by the guarantees supporting the credit facility.

 

Initial borrowings under the credit facility were used (i) to pay off and terminate Nytis LLC’s existing credit facility with Bank of Oklahoma, (ii) to pay the purchase price of the EXCO Acquisition, (iii) to pay costs and expenses associated with the EXCO Acquisition and (iv) to provide working capital for the Company.

 

As of December 31, 2016, there were approximately $16.2 million in outstanding borrowings and approximately $800,000 of additional borrowing capacity available under the credit facility. The Company’s effective borrowing rate at December 31, 2016 was approximately 5.4%.

 

Note 8 – Income Taxes

 

The provision for income taxes for the years ended December 31, 2016 and 2015 consists of the following:

 

(in thousands)		Year Ended
		December 31, 2016				December 31, 2015
Current income tax expense		$	-			$	-
Deferred income tax (benefit) expense			(4,472	)			(3,733	)
Change in valuation allowance			4,472				3,773
Total income tax expense		$	-			$	-

 

 

Note 8 – Income Taxes (continued)

 

The effective income tax rate for the years ended December 31, 2016 and 2015 differed from the statutory U.S. federal income tax rate as follows:

 

		Year Ended
		December 31, 2016				December 31, 2015
Federal income tax rate			35.0	%			35.0	%
State income taxes, net of federal benefit			3.5				3.5
Percentage depletion in excess of basis			1.1				1.3
Non-controlling interest in consolidated partnerships			(.4	)			(.4	)
True-up of prior year depletion in excess of basis			.2				.2
Stock-based compensation deficiency			(2.9	)			(1.8	)
Rate changes of prior year deferreds			(1.6	)			4.2
Increase in valuation allowance and other			(34.9	)			(42.0	)
Total income tax expense			-				-

  

The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities at December 31, 2016 and 2015 are presented below:

 

(in thousands)		December 31, 2016				December 31, 2015
Deferred tax assets
Net operating loss carryforwards		$	8,274			$	5,433
Depletion carryforwards			2,740				2,570
Accrual and other			1,694				1,318
Derivatives			730				(213	)
Asset retirement obligations			1,936				1,168
Property, plant and equipment			6,439				7,185
Total deferred tax assets			21,813				17,461
Deferred tax liability
Interest in partnerships			(762	)			(757	)
Less valuation allowance			(21,051	)			(16,704	)
Net deferred tax asset		$	-			$	-

 

The Company has net operating losses (“NOL”) of approximately $19.7 million available to reduce future years’ federal taxable income. The federal net operating losses expire beginning in 2031 through 2036. The Company has NOL of approximately $34.4 million available to reduce future years’ state taxable income. These state NOL carryforwards will expire beginning in 2023 through 2036 depending on 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. 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, 2016, 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 9 – Stockholders’ Equity

 

Authorized and Issued Capital Stock

 

Effective March 15, 2017 and pursuant to a reverse stock split approved by the shareholders and Board of Directors, each 20 shares of issued and outstanding common stock became one share of common stock and no fractional shares were issued. References to the number of shares and price per share give retroactive effect to the reverse stock split for all periods presented.

 

As of December 31, 2016, the Company had 200,000,000 shares of common stock authorized with a par value of $0.01 per share, of which approximately 5.5 million were issued and outstanding and 1,000,000 shares of preferred stock with a par value of $0.01 per share, none of which were issued and outstanding. During the year ended December 31, 2016, the increase in the Company’s issued and outstanding common stock reflect restricted stock, and performance units net of shares exchanged for payroll tax obligations paid by the Company, that vested during the year.

 

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, 2016, the Company has 12,500 warrants granted by SLSC prior to the merger outstanding and exercisable and approximately 24,000 shares of common stock outstanding that are subject to restricted stock agreements.

 

Nytis USA Warrants

 

As of December 31, 2016, the Company has 12,500 warrants outstanding and exercisable, which were granted by SLSC prior to the merger. These warrants have an exercise price of $20.00 and expire on August 31, 2017.

 

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, 2016, there were approximately 24,000 shares of unvested restricted stock granted under the Nytis USA Restricted Stock Plan (“Nytis USA Plan”). The Company accounted for these grants at their intrinsic value. From the dates of grant through March 31, 2013, the Company estimated that none of these shares would vest and accordingly, no compensation cost had been recorded through March 31, 2013.

 

In June 2013, the vesting terms of these restricted stock grants were modified so that 25% of the shares would vest on the first of January from 2014 through 2017. As such, the Company is recognizing compensation expense for these restricted stock grants based on the fair value of the shares on the date the vesting terms were modified. Compensation costs recognized for these restricted stock grants were approximately $335,000 for the years ended December 31, 2016 and 2015. As of December 31, 2016, compensation costs relative to these restricted stock have been fully recognized.

 

Carbon Stock Incentive Plans

 

The Company has two stock plans, the Carbon 2011 Stock Incentive Plan and the Carbon 2015 Stock Incentive Plan (collectively the “Carbon Plans”). The Carbon Plans were approved by the shareholders of the Company and in the aggregate provide for the issuance of approximately 1.1 million shares of common stock to Carbon officers, directors, employees or consultants eligible to receive the awards under the Carbon plans. The Carbon Plans provide for granting Director Stock Awards to non-employee directors and for granting Incentive Stock Options, Non-qualified Stock Options, Restricted Stock Awards, Performance Awards and Phantom Stock Awards, or a combination of the foregoing, as is best suited to the circumstances of the particular employee, officer, director or consultant.

 

 

Note 9 – Stockholders’ Equity (continued)

 

Restricted Stock

 

Restricted stock awards for employees vest ratably over a three-year service period or cliff vest at the end of a three year service period. For non-employee directors, the awards vest upon the earlier of a change in control of 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 between 2014 and 2016, 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 Plans as of December 31, 2016 and 2015 as well as activity during the years then ended.

 

						Weighted Avg
		Number				Grant Date
			of Shares				Fair Value
Restricted stock awards, nonvested, January 1, 2015			176,167			$	12.26
Granted			87,000				8.00
Vested			(64,167	)			12.33
Restricted stock awards, nonvested, December 31, 2015			199,000				10.37
Granted			134,501				5.40
Vested			(64,668	)			10.84
Forfeited			(1,083	)			6.20
Restricted stock awards, nonvested, December 31, 2016			267,750			$	7.78

 

Compensation costs recognized for these restricted stock grants were approximately $742,000 and $762,000 for the years ended December 31, 2016 and 2015, respectively. As of December 31, 2016, there was approximately $1.2 million of unrecognized compensation costs related to these restricted stock grants which the Company expects to be recognized over the next 6.3 years.

 

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 certain performance measures relative to a defined peer group or the growth of certain performance measures over a defined period of time for the Company as well as the lapse of forfeiture restrictions pursuant to the terms and conditions of the agreements including for certain of the grants, the requirement of continuous employment by the grantee prior to a change in control of the Company. The following table shows a summary of the Company’s unvested performance units as of December 31, 2016 and 2015 as well as activity during the years then ended.

 

 

Note 9 – Stockholders’ Equity (continued)

 

		Number
		of Shares
Restricted performance units, non-vested, January 1, 2015			234,311
Granted			80,000
Restricted performance units, non-vested, December 31, 2015			314,311
Granted			80,000
Vested			(84,480	)
Forfeited			(13,520	)
Restricted performance units, non-vested, December 31, 2016			296,311

 

The Company accounts for the performance units granted during 2012 and 2014 through 2016 at their fair value determined at the date of grant, which were $12.80, $11.80, $8.00 and $5.40 per share, respectively. The final measurement of compensation cost will be based on the number of performance units that ultimately vest. At December 31, 2016, the Company estimated that none of the performance units granted in 2012 and 2016 would vest whether due to change in control or other performance provisions and accordingly, no compensation cost has been recorded for these performance units. During 2016, the Company estimated that it was probable that a portion of the performance units granted in 2014 and 2015 would vest and therefore compensation costs of approximately $1.2 million related to these performance units were recognized for the year ended December 31, 2016. As of December 31, 2016, 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, 2014 through 2016 would be approximately $2.5 million.

 

The performance units granted in 2013 contained specific vesting provisions, and did not contain 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 2014-2016, the Company recognizes compensation expense for the performance units granted in 2013 based on the grant date fair value of the performance units, amortized ratably over three years (the performance period). The fair value of the performance units granted in 2013 was estimated using a Monte Carlo simulation (“MCS”) valuation model. 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 and 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 $10.80 per share. Compensation costs recognized for these performance units were approximately $127,000 and $346,000 for the years ended December 31, 2016 and 2015, respectively. As of December 31, 2016, compensation costs relative to these performance units have been fully recognized.

 

Note 10 – Accounts Payable and Accrued Liabilities

 

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

 

(in thousands)		As of December 31,
		2016				2015
Accounts payable		$	2,315			$	577
Oil and gas revenue payable to oil and gas property owners			1,415				862
Gathering and transportation payables			468				359
Production taxes payable			113				59
Drilling advances received from joint venture partner			955				2,115
Accrued drilling costs			4				112
Accrued lease operating costs			282				76
Accrued ad valorem taxes			1,552				496
Accrued general and administrative expenses			1,572				833
Accrued income taxes payable			-				-
Accrued interest			184				3
Other liabilities			261				129
Total accounts payable and accrued liabilities		$	9,121			$	5,621

 

 

Note 11 – 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, 2016 and 2015 by level within the fair value hierarchy:

 

(in thousands)		Fair Value Measurements Using
		Level 1				Level 2				Level 3				Total
December 31, 2016
Liabilities:
Commodity derivatives		$	-			$	1,932			$	-			$	1,932
December 31, 2015
Assets:
Commodity derivatives		$	-			$	559			$	-			$	559

 

As of December 31, 2016, the Company’s commodity derivative financial instruments are comprised of eight natural gas and nine oil swap agreements. As of December 31, 2015, the Company’s commodity derivative financial instruments were comprised of three natural gas swap agreements and one gas and four oil costless collar agreements. The fair values of these agreements are determined under an income valuation technique. The valuation model requires a variety of inputs, including contractual terms, published forward prices, volatilities for options and discount rates, as appropriate. The Company’s estimates of fair value of derivatives include consideration of the counterparty’s credit worthiness, the Company’s credit worthiness and the time value of money. The consideration of these factors 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 for all of the Company’s outstanding commodity derivative financial instruments as of December 31, 2016 is BP Energy Company.

 

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, 2016 and 2015, the Company recorded asset retirement obligations for additions of approximately $1.8 million and $4,000, respectively. See Note 3 for additional information.

 

To determine the fair value of the proved developed properties acquired in 2016, the Company primarily used the income approach and made market assumptions as to projections of estimated quantities of oil and natural gas reserves, future production rates, future commodity prices including price differentials as of the Closing Date, future operating and development costs and a market participant weighted average cost of capital.

 

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 12 – 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 has historically entered into fixed price delivery contracts to effectively provide commodity price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded at fair value in the Consolidated Financial Statements.

 

Pursuant to the terms of the Company’s credit facility with LegacyTexas Bank, the Company has entered into swap derivative agreements to hedge certain of its oil and natural gas production for 2017 through 2019. As of December 31, 2016, these derivative agreements consisted of the following:

 

		Natural Gas								Oil
						Weighted								Weighted
						Average								Average
Year		MMBtu				Price (a)				Bbl				Price (b)
2017			3,360,000			$	3.30				60,000			$	52.98
2018			3,120,000			$	3.01				48,000			$	54.11
2019			1,320,000			$	2.85				36,000			$	54.90

 

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

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

 

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,
		2016				2015
Commodity derivative contracts:
Current assets		$	-			$	408
Non-current assets		$	-			$	151
Current liabilities		$	1,341			$	-
Non-current liabilities		$	591			$	-

 

 

Note 12 – Physical Delivery Contracts and Commodity Derivatives (continued)

 

The table below summarizes the commodity settlements and unrealized gains and losses related to the Company’s derivative instruments for the years ended December 31, 2016 and 2015. These commodity settlements and unrealized gains and losses are recorded and included in commodity derivative gain or loss in the accompanying Consolidated Statements of Operations.

 

(in thousands)		For the year ended December 31,
		2016				2015
Commodity derivative contracts:
Settlement gains		$	231			$	1,615
Unrealized losses			(2,490	)			(763	)
Total settlement and unrealized (losses) gains, net		$	(2,259	)		$	852

 

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

 

The counterparty in all of the Company’s derivative instruments is BP Energy Company. The Company has entered into an ISDA Master Agreement with BP Energy Company that establishes standard terms for the derivative contracts and an inter-creditor agreement with LegacyTexas Bank and BP Energy Company whereby any credit exposure related to the derivative contracts entered into by the Company and BP Energy Company is secured by the collateral and backed by the guarantees supporting the credit facility.

 

The Company nets its derivative instrument fair value amounts executed with its counterparty pursuant to an ISDA master agreement, which provides for the net settlement over the term of the contracts and in the event of default or termination of the contracts. The following table summarizes the location and fair value amounts of all derivative instruments in the Consolidated Balance Sheet, as well as the gross recognized derivative assets, liabilities and amounts offset in the Consolidated Balance Sheet as of December 31, 2016.

 

												Net
				Gross								Recognized
				Recognized				Gross				Fair Value
				Assets/				Amounts				Assets/
		Balance Sheet Classification		Liabilities				Offset				Liabilities
Commodity derivative assets:
		Current assets		$	-			$	-			$	-
		Other long-term assets			249				(249	)			-
Total derivative assets				$	249			$	(249	)		$	-
Commodity derivative liabilities:
		Current liability		$	1,341			$	-			$	1,341
		Non-current liabilities			840				(249	)			591
Total derivative liabilities				$	2,181			$	(249	)		$	1,932

 

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 13 – Commitments and Contingencies

 

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, 2016 are summarized in the table below.

 

Period		Dekatherms per day		Demand Charges
Jan 2017 - Apr 2018		5,530		$0.20 - $0.65
May 2018 - Mar 2020		3,230		$0.20 - $0.62
Apr 2020 – May 2020		2,150		$0.20
Jun 2020 – May 2036		1,000		$0.20

 

 

Note 13 – Commitments and Contingencies (continued)

 

A liability of approximately $822,000 related to firm transportation contracts assumed in a 2011 asset acquisition and the EXCO Acquisition in 2016, which represents the remaining commitment, is reflected on the Company’s Consolidated Balance Sheet as of December 31, 2016. The fair value of these firm transportation obligations were determined based upon the contractual obligations assumed by the Company and discounted based upon the Company’s effective borrowing rate. These contractual obligations are being amortized on a monthly basis as the Company pays these firm transportation obligations in the future.

 

The Company leases, under an operating lease arrangement, approximately 5,500 square feet of administrative office space in Denver, Colorado and approximately 5,300 square feet of office space in Lexington, Kentucky, both of which expire in 2019. For the years ended December 31, 2016 and 2015, the Company incurred rental expenses of $220,000 and $236,000, respectively. The Company has minimum lease payments for its office space and equipment of approximately $260,000 for 2017, $263,000 for 2018 and $263,000 for 2019.

 

Note 14 – Retirement Savings Plan

 

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, 2016 and 2015, the Company paid approximately $99,000 and $277,000, respectively, for 401(k) contributions and related administrative expenses. During 2016, as part of a cost reduction measure, the Company temporarily suspended its 401 (k) match from August through December.

 

Note 15 – Supplemental Cash Flow Disclosure

 

Supplemental cash flow disclosures for the years ended December 31, 2016 and 2015 are presented below:

 

(in thousands)		For the Year Ended December 31,
		2016				2015
Cash paid during the period for:
Interest payments		$	156			$	166
Income taxes			-				325
Non-cash transactions:
Increase in net asset retirement obligations		$	1,849			$	4
Increase (decrease) in accounts payable and accrued liabilities included in oil and gas properties		$	1,099			$	(215	)
Obligations assumed with acquisitions		$	2,694			$	-

 

Note 16 – Subsequent Events

 

On March 15, 2017 and pursuant to a reverse stock split approved by the shareholders and Board of Directors, each 20 shares of issued and outstanding common stock became one share of common stock and no fractional shares were issued. All references to the number of shares of common stock and per share amounts give retroactive effect to the reverse stock split for all periods presented.

 

On February 15, 2017, the Company entered into an Amended and Restated Limited Liability Company Agreement (“LLC Agreement”) of Carbon California, a Delaware limited liability company established by the Company. Pursuant to the LLC Agreement, Carbon acquired a 17.813% interest in Carbon California represented by Class B Units and will be the sole manager of Carbon California. The Class B Units were acquired for no cash consideration. In connection with its role as the sole manager of Carbon California, a portion of the Company’s general and administrative expenses will be allocated to and paid by Carbon California. The negotiation and diligence of the oil and gas acquisitions described below was led by the Company and at the closing of the acquisitions, the Company was reimbursed $500,000 for its time and expenditures related to such efforts.

 

On February 15, 2017, Carbon California (i) issued and sold Class A Units to two institutional investors for an aggregate cash consideration of $22 million, (ii) entered into a Note Purchase Agreement (the “Note Purchase Agreement”) with two institutional investors for the issuance and sale of up to $25 million of Senior Secured Revolving Notes (the “Senior Revolving Notes”) due February 15, 2022 and (iii) entered into a Securities Purchase Agreement (the “Securities Purchase Agreement”) with one institutional investor for the issuance and sale of $10 million of Senior Subordinated Notes (the “Subordinated Notes”) due February 15, 2024. The closing of the Note Purchase Agreement and the Securities Purchase Agreement on February 15, 2017, resulted in the sale and issuance by Carbon California LLC of (xi) Senior Revolving notes in the principal amount of $10 million and (xii) Subordinated Notes in the original principal amount of $10 million. The maximum principal amount available under the Senior Revolving Notes is based upon the borrowing base attributable to Carbon California’s proved oil and gas reserves which is to be determined at least semi-annually. The current borrowing base is $15 million.

 

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

 

 

Note 16 – Subsequent Events (continued)

 

In connection with the Company entering into the LLC Agreement described above and Carbon California engaging in the transactions also described above, the Company issued to an affiliate of one of the institutional investors which purchased Class A Units of Carbon California (which is also an affiliate of the Company’s largest stockholders), a warrant to purchase shares of the Company’s common stock at an exercise price of $7.20 per share (the “Warrant”). The exercise price for the Warrant is payable exclusively with Class A Units of Carbon California and the number of shares of the Company’s common stock for which the Warrant is exercisable is determined, as of the time of exercise, by dividing (a) the aggregate unreturned capital of the Warrantholder’s Class A Units of Carbon California by (b) the exercise price. The Warrant has a term of seven years and includes certain standard registration rights with respect to the shares of the Company’s common stock issuable upon exercise of the Warrant. If exercised, the Warrant provides the Company an opportunity to increase its ownership stake in Carbon California without requiring the payment of cash. As of the date hereof, the Warrant is exercisable for an aggregate of 1,527,778 shares of the Company’s common stock.

 

The borrowing base under the Company’s credit facility is subject to semi-annual redeterminations in March and September, commencing March 2017. On March 30, 2017, the borrowing base was increased from $17.0 million to $23.0 million. 

 

Note 17– Supplemental Financial Data – Oil and Gas Producing Activities (unaudited)

 

Estimated Proved Oil and Gas Reserves

 

The reserve estimates as of December 31, 2016 and 2015 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, 2016 and 2015 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 2016 and 2015 are presented in the table below. Proved oil and gas reserves are those quantities of oil and 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 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, 2016 and 2015 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, 2016 and 2015. 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, 2016 and 2015. See Note 3 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.

 

A summary of the Company’s changes in quantities of proved oil and gas reserves for the years ended December 31, 2016 and 2015 are as follows:

 

		2016												2015
		Oil				Natural Gas				Total				Oil				Natural Gas				Total
		MBbls				MMcf				MMcfe				MBbls				MMcf				MMcfe
Proved reserves, beginning of year			598				29,958				33,546				853				36,948				42,066
Revisions of previous estimates			110				2,207				2,867				(185	)			(4,670	)			(5,780	)
Extensions and discoveries			-				-				-				31				-				186
Production			(79	)			(2,823	)			(3,297	)			(101	)			(2,040	)			(2,646	)
Purchases of reserves in-place			253				44,923				46,441				-				138				138
Sales of reserves in-place			-				-				-				-				(418	)			(418	)
Proved reserves, end of year			882				74,265				79,557				598				29,958				33,546
Proved developed reserves at:
End of Year			851				74,265				79,371				554				29,958				33,282
Proved undeveloped reserves at:
End of Year			31				-				186				44				-				264

 

 

Note 17 – Supplemental Financial Data – Oil and Gas Producing Activities (unaudited) (continued)

 

The estimated proved reserves for December 31, 2016 and 2015 includes approximately 3.1 and 3.0 Bcfe, respectively, attributed to non-controlling interests of consolidated partnerships.

 

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:

 

		2016				2015
		(in thousands)
Oil and gas properties
Proved oil and gas properties		$	112,579			$	97,453
Unproved properties not subject to depletion			1,999				3,194
Accumulated depreciation, depletion, amortization and impairment			(78,596	)			(72,421	)
Net oil and gas properties		$	35,982			$	28,226

 

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, 2016 and 2015:

 

		2016				2015
		(in thousands)
Property acquisition costs:
Unevaluated properties		$	97			$	341
Proved properties and gathering facilities			8,117				-
Development costs			360				2,106
Gathering facilities			42				578
Asset retirement obligation			1,849				4
Total costs incurred		$	10,465			$	3,029

 

The Company’s investment in unproved properties as of December 31, 2016, by the year in which such costs were incurred is set forth in the table below:

 

		2016				2015				2014 and Prior
		(in thousands)
Acquisition costs		$	97			$	341			$	1,561

 

Results of Operations from Oil and Gas Producing Activities

 

Results of operations from oil and gas producing activities for the years ended December 31, 2016 and 2015 are presented below:

 

		2016				2015
		(in thousands)
Oil and gas sales, including commodity derivative gains and losses		$	8,184			$	11,560
Expenses:
Production expenses			5,640				5,507
Depletion expense			1,839				2,466
Accretion of asset retirement obligations			176				123
Impairment of oil and gas properties			4,299				5,419
Total expenses			11,954				13,515
Results of operations from oil and gas producing activities		$	(3,770	)		$	(1,955	)
Depletion rate per Mcfe		$	0.56			$	0.93

 

 

Note 17 – Supplemental Financial Data – Oil and Gas Producing Activities (unaudited) (continued)

 

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%.

 

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,
		2016				2015
		(in thousands)
Future cash inflows		$	214,658			$	102,741
Future production costs			(103,252	)			(47,117	)
Future development costs			(315	)			(420	)
Future income taxes			(14,858	)			-
Future net cash flows			96,233				55,204
10% annual discount			(51,522	)			(30,172	)
Standardized measure of discounted future net cash flows		$	44,711			$	25,032

 

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,
		2016				2015
		(in thousands)
Standardized measure of discounted future net cash flows, beginning of year		$	25,032			$	65,006
Sales of oil and gas, net of production costs and taxes			(4,804	)			(5,283	)
Price revisions			(786	)			(37,490	)
Extensions, discoveries and improved recovery, less related costs			-				384
Changes in estimated future development costs			248				3,290
Development costs incurred during the period			102				-
Quantity revisions			2,091				(4,282	)
Accretion of discount			2,503				6,702
Net changes in future income taxes			(4,633	)			2,010
Purchases of reserves-in-place			26,776				115
Sales of reserves-in-place			-				(380	)
Changes in production rate timing and other			(1,818	)			(5,040	)
Standardized measure of discounted future net cash flows, end of year		$	44,711			$	25,032

 

The twelve month weighted averaged adjusted prices in effect at December 31, 2016 and 2015 were as follows:

 

		2016				2015
Oil (per Bbl)		$	40.40			$	46.12
Natural Gas (per Mcf)		$	2.41			$	2.50

 

 

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, 2016 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, 2016, 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, 2016, 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		60		Chief Executive Officer, Director
Mark D. Pierce		63		President
Kevin D. Struzeski		58		Chief Financial Officer, Treasurer and Secretary
James H. Brandi		68		Chairman of the Board
David H. Kennedy		67		Director
Bryan H. Lawrence		74		Director
Peter A. Leidel		60		Director
Edwin H. Morgens		75		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 from June 2012 until the completion of its business combination with Sabine Oil & Gas in December 2014. Mr. McDonald also is Chairman of the Board of Prairie Provident Resources (TSX: PPR), an exploration and production company based in Calgary, Alberta, Canada. Mr. McDonald received a Bachelor’s degree in both 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 is 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 is 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 from February 2011 to March 2012. Mr. Kennedy has served as Executive Advisor to Cadent Energy Partners since 2005. He was director and chairman of the audit committee of Logan International Inc. from 2006 until the sale of the company in 2016. 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 2003, Mr. Kennedy was a director of Carbon Energy Corporation before its merger with Evergreen Resources in 2003. 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. He was a Certified Public Accountant.

 

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 contributes 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 Star Gas Partners, L.P. (NYSE:SGU), Hallador Energy Company (NASDAQ:HNRG) and certain non-public companies in the energy industry in which Yorktown partnerships hold equity interests. Mr. Lawrence served as a director of Approach Resources, Inc., 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 is 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), Extraction Oil & Gas, Inc. (NASDAQ: XOG) and certain non-public companies in the energy industry in which 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 is 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, Waterfall, 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, Scientific American Magazine Inc. and the Henry J. Kaiser Family Foundation. He is currently a trustee of the American Museum of Natural History, an Overseer of the Weill Cornell Medical College 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 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 from 1977 until 1997 was employed by Ashland Exploration, Inc. attaining the position of Vice President Eastern Region and Gas Marketing. 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 has been the Company’s Treasurer and Secretary since 2011 and has been the Chief Financial Officer, Treasurer and Secretary of Nytis USA since 2005.  From 2003 to 2004, Mr. Struzeski was the Director of Treasury at 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 at the annual meeting of our stockholders or through the affirmative vote of the holders of a majority of the Company’s voting stock in lieu of a meeting. 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.

 

In July 2015, Sabine Oil and Gas filed for bankruptcy protection under Chapter 11. Mr. McDonald was a director of Sabine Oil and Gas. The Board does not believe this disclosure is material to an evaluation of the ability or integrity of Mr. McDonald because of the extenuating circumstances relating to Sabine Oil and Gas’ business and industry.

 

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, 2016, we believe that during the Company’s 2016 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 Business Conduct and Ethics that applies to all directors of the Company. A copy of the Code of Business Conduct and Ethics is available on our website at http://www.carbonnaturalgas.com.

 

 

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 four meetings during 2016.

 

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 stock incentive plans. The Compensation, Nominating and Governance 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.

 

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 also monitors corporate governance for the Board, which includes reviewing the Code of Business Conduct and Ethics and evaluation of board and committee performance.

 

The Compensation, Nominating and Governance Committee was formed in September 2012 and held five meetings during 2016.

 

Item 11.    Executive Compensation.

Summary Compensation Table

 

Effective March 15, 2017 and pursuant to the reverse stock split approved by the shareholders and Board of Directors, each 20 shares of issued and outstanding common stock became one share of common stock and no fractional shares were issued. The tables under Item 11, Executive Compensation, give retroactive effect to the reverse stock split for all periods presented.

 

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, 2016 and 2015.

 

Name and Principal Position		Year		Salary ($)				Stock Awards ($) (1)				Non-Equity Incentive Plan Compensation ($)				All Other Compensation ($)(2)				Total ($)
Patrick R. McDonald		2016			350,000				108,000				194,947				77,480				730,427
Chief Executive Officer		2015			350,000				160,000				346,140				99,876				956,016
Mark D. Pierce		2016			236,000				108,000				85,442				9,264				438,706
President		2015			235,662				80,000				155,763				24,168				495,593
Kevin D. Struzeski		2016			247,000				108,000				89,425				46,335				490,760
Chief Financial Officer, Treasurer and Secretary (1)		2015			247,000				80,000				162,686				75,636				565,322

 

(1)	Reflects the full grant date fair value of restricted stock awards granted in 2016 and 2015 calculated in accordance with FASB ASC Topic 718.

 

(2)	All other compensation in 2016 and 2015 was comprised of (i) unused vacation, (ii) contributions made by the Company to its 401(k) plan, (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 compensation 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	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, minimal 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 believe that base salaries for our executive officers are appropriate for persons serving as executive officers of public companies similar in size and complexity to the Company.

 

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.  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 2016 were determined under the provisions of the Carbon Natural Gas Company 2015 Annual Incentive Plan whereby seventy percent of the AIP payments were determined at the discretion of the Board taking into consideration the factors listed above and thirty percent of the AIP payments were determined and weighted based upon the performance measures and objectives as follows:

 

Performance Measure		Weighting		Objective
Lease Operating Expense		33 1/3%		$.87/Mcfe (15:1 equivalent basis)
General and Administrative Expenses		33 1/3%		$5.4 million of cash-based general and administrative expenses
Debt/EBITDA Ratio		33 1/3%		Debt/EBITDA ratio of 1.6

 

Payments in 2015 were determined under the provisions of the Carbon Natural Gas Company 2014 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		20%		20% increase
Net Total Proved Reserve Growth		10%		5% increase
Net Annual Production Growth		20%		10% increase
Lease Operating Expenses ($/unit)		20%		$1.10/Mcfe (6:1 equivalent basis)
G&A per Unit of Production ($/unit)		10%		$.80 per unit of production equivalent
F&D cost per Unit of Reserves		20%		$1.70 per unit of reserve equivalent
Total of Performance Measures		100.00%

 

Other Compensation/Benefits. Another element of the overall compensation is to provide 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) plan 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 2016.

 

		Fees Earned or
		Paid in Cash
Name(1)		($)
James H. Brandi			30,000
David H. Kennedy			20,000
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 above under “Executive Compensation – Summary Compensation Table.”

 

 

During 2016, Mr. Brandi was awarded 5,000 restricted shares of our common stock and Messrs. Kennedy, Lawrence, Leidel and Morgens were each awarded 4,000 restricted shares of our common stock. The aggregate number of unvested restricted stock awards outstanding at December 31, 2016 for each of our non-employee directors is as follows:

 

		Unvested
		Restricted Stock Awards
Name		December 31, 2016
James H. Brandi			22,000
David H. Kennedy			8,000
Bryan H. Lawrence			20,000
Peter A. Leidel			20,000
Edwin H. Morgens			20,000

  

Outstanding Equity Awards at December 31, 2016

 

The following tables sets forth information concerning unexercised warrants and unvested restricted stock and performance unit awards, each as held by our executive officers as of December 31, 2016.

 

WARRANT AWARDS

Award Recipient

Option for # of Shares

# Vested

Exercise Price per Share

Date Granted

Expiration

Former SLSC Officers and Directors

12,500

12,500

$

20.00

01/10/2007

08/31/2017

 

STOCK AWARDS
		Equity Incentive Plan Awards								Market Value
		# of Unvested Shares								of Unvested
		Restricted				Performance				Shares
Award Recipient		Stock				Units				$(2)
Patrick R. McDonald			18,880	(1)			-				169,920
			40,000				78,080				1,062,720
			58,880				78,080				1,232,640
Mark D. Pierce			510	(1)			-				4,590
			30,000				46,540				688,860
			30,510				46,540				693,450
Kevin D. Struzeski			5,096	(1)			-				45,864
			30,000				46,540				688,860
			35,096				46,540				734,724

 

The following table reflects unvested stock awards held by our executive officers as of December 31, 2016 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		2017				2018				2019				Thereafter
Patrick R. McDonald			38,881				13,333				6,666				-
Mark D. Pierce			10,509				6,667				13,334				-
Kevin D. Struzeski			15,095				6,667				13,334				-

 

 

The following table reflects unvested performance stock awards held by our executive officers as of December 31, 2016 that vest upon the achievement of certain performance measures relative to a defined peer group or the growth of certain performance measures over a defined period of time for the Company 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. 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 awards based upon the achievement of certain performance measures relative to a defined peer group or the growth of certain performance measures over a defined period of time for the Company.

 

						Stock Price and Defined Performance Measures
Stock Award Recipient		Change of Control				Relative to Peer Group
Patrick R. McDonald			18, 080				60,000
Mark D. Pierce			9,040				37,500
Kevin D. Struzeski			9,040				37,500

 

(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)	Reflects the value of unvested shares of restricted stock and performance unit awards held by our executive officers as of December 31, 2016 measured by the closing market price of our common stock on December 31, 2016, which was $9.00 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 a term through December 31, 2017, which term shall automatically be extended for successive terms of one-year provided, however, that the Board of Directors may terminate the agreement at the end of the 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 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 a term through December 31, 2017, which term shall automatically be extended for successive terms of one-year provided, however, that the Board of Directors may terminate the agreement at the end of the 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 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.

Effective March 15, 2017 and pursuant to the reverse stock split approved by the shareholders and Board of Directors, each 20 shares of issued and outstanding common stock became one share of common stock and no fractional shares were issued. The table under Item 12, Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, give retroactive effect to the reverse stock split for all periods presented.

 

As of March 17, 2017 the Company had 5,482,673 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			896,915				16.4	%
Yorktown Energy Partners VI, L.P. 410 Park Avenue 19th Floor New York, NY 10022			896,915				16.4	%
Yorktown Energy Partners IX, L.P. 410 Park Avenue 19th Floor New York, NY 10022			1,111,111				20.3	%
Arbiter Partners Capital Management LLC (3) 530 Fifth Avenue 20th Floor New York, NY 10036			655,733				12.0	%
AWM Investment Company Inc. (4) c/o Special Situation Funds 527 Madison Avenue Suite 2600 New York, New York 10022			706,553				12.9	%

 

  

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)			8,154				*
Bryan H. Lawrence, Director (7)			2,904,941				53.0	%
Peter A. Leidel, Director  (8)			2,904,941				53.0	%
Patrick R. McDonald, Chief Executive Officer and Director (9)			160,246				2.9	%
Edwin H. Morgens, Director (10)			83,333				1.5	%
Mark D. Pierce, President(11)			45,594				*
Kevin D. Struzeski, Chief Financial Officer, Treasurer and Secretary(12)			67,231				2.9	%
All directors and executive officers as a group (eight persons)(13)			3,269,499				59.2	%

 

*	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)

Includes 444,444 shares owned by Arbiter Partners QP, LP. Arbiter Partners QP, LP holds sole voting and investment power over these shares. Arbiter Partners Capital Management LLC acts as investment advisor on behalf of Arbiter Partners QP, LP and on behalf of certain other managed accounts none of which hold more than five percent of the common stock of the Company.

 

(4)

Consists of (i) 490,188 common stock shares owned by Special Situations Fund III QP, L.P. (“SSFQP”), (ii) 144,135 common stock shares owned by Special Situations Cayman Fund, L.P. (“Cayman”), and (iii) 72,230 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.

 

(5)	Does not include 22,000 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 8,000 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) 896,915 common stock shares owned by Yorktown Energy Partners V, L.P., (ii) 896,915 common stock shares owned by Yorktown Energy Partners VI, L.P. and (iii) 1,111,111 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 20,000 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) 896,915 common stock shares owned by Yorktown Energy Partners V, L.P., (ii) 896,915 common stock shares owned by Yorktown Energy Partners VI, L.P. and (iii) 1,111,111 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 20,000 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) 24,135 shares owned by McDonald Energy, LLC over which Mr. McDonald has voting and investment power, and (ii) 20,000 shares of restricted stock that will vest within 60 days. Does not include 20,000 and 78,080 shares of unvested restricted and performance units, respectively.

 

(10)	Does not include 20,000 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 10,000 shares of restricted stock that will vest within 60 days. Does not include 20,000 and 46,500 shares of unvested restricted stock and performance units, respectively.

 

(12)	Includes 10,000 shares of restricted stock that will vest within 60 days. Does not include 20,000 and 46,500 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 adopted the 2011 Stock Incentive Plan and the 2015 Stock Incentive Plan (collectively the “Plans”) and such Plans were approved by the stockholders during annual stockholders’ meetings on December 8, 2011 and June 25, 2015, respectively. As of December 31, 2016 the Company has issued 462,000 restricted shares and 400,500 restricted performance units under the Plans. Information regarding options outstanding at December 31, 2016 is set forth under the heading “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities - Securities Authorized for Issuance Under Compensation Plans” above.

 

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

Certain Relationships

 

None

 

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, 2016.

 

Employment Agreements

 

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

 

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 $168,000 and $178,000 for the fiscal years ended December 31, 2016 and 2015, respectively. These amounts were billed for professional services that EKSH provided for the audit of our annual financial statements, an audit related to the statements of revenues and direct operating expenses for the interests acquired in the EXCO Acquisition, 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, 2016 and 2015.

 

All Other Fees

 

EKSH billed us for permitted, pre-approved information technology support fees of approximately $54,000 and $64,000 for the fiscal years ended December 31, 2016 and 2015, 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 2016 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, 2016 and 2015

3.       Consolidated Statements of Operations—Years Ended December 31, 2016 and 2015

4.       Consolidated Statements of Shareholders' Equity—Years Ended December 31, 2016 and 2015

5.       Consolidated Statements of Cash Flows—Years Ended December 31, 2016 and 2015

6.       Notes to Consolidated Financial Statements—Years Ended December 31, 2016 and 2015

(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		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.
2.2		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.
2.3		Purchase and Sale Agreement by and among Nytis Exploration Company LLC, Liberty Energy, LLC and Continental Resources, Inc., dated October 15, 2014, incorporated by reference to Exhibit 2.5 to Form 10-K filed on March 31, 2015.  Portions of the Purchase and Sale Agreement have been omitted pursuant to a request for confidential treatment.
2.4*		Purchase and Sale Agreement by and among Nytis Exploration Company LLC, EXCO Production Company (WV), LLC, BG Production Company (WV), LLC and EXCO Resources (PA), dated October 1, 2016, filed herewith.
3(i)(a)*		Amended and Restated Certificate of Incorporation of Carbon Natural Gas Company, as amended, filed herewith.
3(ii)		Amended and Restated Bylaws, incorporated by reference to Exhibit 3(i) to Form 8-K filed on May 5, 2015.
10.1*		Credit Agreement, by and between the Company, Nytis Exploration Company LLC, Nytis Exploration (USA) Inc. and LegacyTexas Bank, dated October 3, 2016, filed herewith. Portions of the Schedules to the Credit Agreement have been omitted pursuant to a request for confidential treatment.
10.1(a)*		Unconditional Guaranty from Nytis Exploration Company, LLC and Nytis Exploration Company (USA) Inc. to LegacyTexas Bank, dated October 3, 2016, filed herewith.
10.1(b)*		Security Agreement from Carbon Natural Gas Company, Nytis Exploration Company LLC and Nytis Exploration Company (USA) Inc. to LegacyTexas Bank, dated October 3, 2016, filed herewith. Portions of the Schedules to the Security Agreement have been omitted pursuant to a request for confidential treatment.
10.2		Employment Agreement between the Company and Patrick McDonald, incorporated by reference to Exhibit 10.2 to Form 8-K filed on April 5, 2013.
10.3		Employment Agreement between the Company and Mark Pierce, incorporated by reference to Exhibit 10.3 to Form 8-K filed on April 5, 2013.
10.4		Employment Agreement between the Company and Kevin Struzeski, incorporated by reference to Exhibit 10.4 to Form 8-K filed on April 5, 2013.
10.5		Carbon Natural Gas Company 2015 Annual Incentive Plan, incorporated by reference to exhibit 10.2 to Form 10-Q filed on May 14, 2015.
10.6		Carbon Natural Gas Company 2015 Stock Incentive Plan incorporated by reference to exhibit 10.12 to Form 10-K filed on March 28, 2016.
10.7		Carbon Natural Gas Company 2016 Annual Incentive Plan, incorporated by reference to exhibit 10.1 to Form 10-Q filed on May 23, 2016.
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, 2017	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, 2017
Patrick R. McDonald		(Principal Executive Officer)
/s/ James H. Brandi		Chairman and Director		March 31, 2017
James H. Brandi
/s/ Peter A. Leidel		Director		March 31, 2017
Peter A. Leidel
/s/ Bryan H. Lawrence		Director		March 31, 2017
Bryan H. Lawrence
/s/ Edwin H. Morgens		Director		March 31, 2017
Edwin H. Morgens
/s/ David H. Kennedy		Director		March 31, 2017
David H. Kennedy

 

 

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