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, 2019

 

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 ENERGY CORPORATION

(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:

 

Title of each class		Trading symbol(s)		Name of each exchange on which registered
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 every Interactive Data File required to be submitted 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 such files). Yes ☒  No ☐

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☒	Smaller reporting company	☒
		Emerging growth company	☐

 

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

 

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

 

The aggregate market value of the registrant’s voting and non-voting common stock held by non-affiliates of the registrant as of June 28, 2019, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $19.2 million (based on the closing price of such common stock of $8.00 as reported on otcmarkets.com on such date).

 

As of March 16, 2020, the registrant had 7,816,420 shares of common stock outstanding.

 

Documents incorporated by reference:

 

Certain information required by Part III of Form 10-K is incorporated by reference to the Registrant’s definitive information statement for the 2020 Annual Meeting of Stockholders, which will be filed within 120 days of December 31, 2019.

 

 

 

CARBON ENERGY CORPORATION

TABLE OF CONTENTS

 

				Page No.
PART I
Items 1 and 2.		Business and Properties		1
Item 1A.		Risk Factors		19
Item 1B.		Unresolved Staff Comments		45
Item 3.		Legal Proceedings		45
Item 4.		Mine Safety Disclosures		45
PART II
Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		46
Item 6.		Selected Financial Data		47
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		47
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk		57
Item 8.		Financial Statements and Supplementary Data		58
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosures		92
Item 9A.		Controls and Procedures		92
Item 9B.		Other Information		92
		PART III
Item 10.		Directors, Executive Officers and Corporate Governance		93
Item 11.		Executive Compensation		93
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		93
Item 13.		Certain Relationships and Related Transactions, and Director Independence		93
Item 14.		Principal Accounting Fees and Services		93
		PART IV
Item 15.		Exhibits, Financial Statement Schedules		94
Item 16.		Form 10-K Summary		96
		Signatures		97

 

 

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, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Forward-looking statements are statements other than statements of historical or present facts, that address activities, events, outcomes, and other matters that the Company (as defined herein) 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 several places in this Annual Report on Form 10-K and include statements with respect to, among other things:

 

●

estimates of our oil, natural gas liquids, and natural gas reserves;

 

●

estimates of our future oil, natural gas liquids, 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 and acquisitions;

 

●

our outlook on oil, natural gas liquids, 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 of America

 

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, natural gas and natural gas liquids. See Part I, Item 1 - “Business-Competition” and - “Business-Regulation,” 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 Securities and Exchange Commission (“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 us 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.

 

 

PART I

 

Throughout this Annual Report on Form 10-K, we use the terms “Carbon,” “Company,” “we,” “our,” and “us” to refer to Carbon Energy Corporation and our wholly-owned and majority-owned subsidiaries. Additionally, we refer to Carbon California Company, LLC as “Carbon California,” and we refer to Carbon California, with our proportionate share of 53.92%, as our “majority-owned subsidiary.” We refer to Carbon Appalachian Company, LLC as “Carbon Appalachia”. In the following discussion, we make statements that may be deemed “forward-looking” statements within the meaning of Section 27A of the Securities Act, and Section 21E of the Exchange Act. See “Forward-Looking Statements,” above, 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.

 

Items 1 and 2. Business and Properties

 

Overview

 

Carbon Energy Corporation, a Delaware corporation formed in 2007, is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of oil, natural gas and natural gas liquids (“NGLs”) properties located in the United States. We currently develop and operate oil and gas properties in the Appalachian Basin in Kentucky, Ohio, Tennessee, Virginia and West Virginia, in the Illinois Basin in Illinois and Indiana, and in the Ventura Basin in California through our wholly-owned and majority-owned subsidiaries. We own 100% of the outstanding interests of Carbon Appalachia, and Nytis Exploration (USA) Inc., a Delaware corporation (“Nytis USA”), which in turn owns 98.11% of Nytis Exploration Company LLC, a Delaware limited liability company (“Nytis LLC”). Nytis LLC holds interests in our operating subsidiaries. We own 53.92% of Carbon California which we consolidate for financial reporting purposes as a majority-owned subsidiary. We focus on conventional and unconventional reservoirs, including shale, tight sands and coalbed methane.

 

As of December 31, 2019, directly and through our 53.92% proportionate share of Carbon California, we own working interests in approximately 7,200 gross wells (6,600 net), royalty interests in approximately 1,100 wells and have leasehold positions in approximately 314,000 net developed acres and approximately 1,257,000 net undeveloped acres.

 

The following table shows a summary of reserve and production data as of and for the year ended December 31, 2019:

 

Estimated Total Proved Reserves(1)																Average Net Daily Production (Mcfe/D)				Average Reserve Life (years)
Oil (MMBbls)				NGLs (MMBbls)				Natural Gas (Bcf)				Total (Bcfe)
	17.7				1.3				450.4				564.9				68,993				22.8

 

(1)

Represents 100% of Carbon, Carbon California and Carbon Appalachia. As of December 31, 2019, Carbon holds a 53.92% proportionate share in Carbon California. See Acquisition Highlights.

 

Acquisition Highlights

 

We pursue acquisitions for investment which meet our criteria for investment returns, and which are consistent with our field development strategy. The acquisition of properties in our existing operating areas enable us to leverage our cost control abilities, technical expertise and existing land and infrastructure positions. Our acquisition program is focused on acquisitions of properties which have relatively low base decline, field development opportunities and undeveloped acreage.

 

Carbon Appalachia

 

Carbon Appalachia was formed in 2016 by us, entities managed by Yorktown Energy Partners XI, L.P. (“Yorktown”), a majority stockholder of ours, and entities managed by Old Ironsides Energy, LLC (“Old Ironsides”), to acquire producing assets in the Appalachian Basin in Kentucky, Tennessee, Virginia and West Virginia. Substantial operations commenced in April 2017. Prior to November 1, 2017, Yorktown held 7.95% of the voting interest and 7.87% of the profits interest in Carbon Appalachia. On November 1, 2017, Yorktown exercised a warrant, pursuant to which Yorktown obtained additional shares of common stock in us in exchange for the transfer and assignment by Yorktown of all of its rights in Carbon Appalachia. Following the exercise of this warrant by Yorktown, we owned 26.50% of the voting interest and 27.24% of the profits interest, and Old Ironsides held the remainder of the interests in Carbon Appalachia.

 

 

On December 31, 2018, we acquired all of the Class A Units of Carbon Appalachia owned by Old Ironsides for a purchase price of $58.2 million, subject to purchase price adjustments (“OIE Membership Acquisition”). As a result of the OIE Membership Acquisition, we now own 100% of the voting and profit interests of Carbon Appalachia, along with its direct and indirect subsidiaries. The acquisition was funded with cash, debt and the issuance of notes to Old Ironsides. See Note 3 to the consolidated financial statements.

 

Carbon California

 

Carbon California was formed in 2016 by us, Yorktown and Prudential Capital Energy Partners, L.P., to acquire producing assets in the Ventura Basin in California.

 

We currently serve as the manager of Carbon California and operate its day-to-day administration, pursuant to the terms of the limited liability company agreement of Carbon California and the management services agreement between Carbon California and us, subject to certain approval rights held by the board of directors of Carbon California.

 

Prior to February 1, 2018, we held 17.81% of the voting and profits interests, Yorktown held 38.59% of the voting and profits interests and Prudential Capital Energy Partners, L.P. held 43.59% of the voting and profits interests in Carbon California. On February 1, 2018, Yorktown exercised a warrant, pursuant to which Yorktown obtained additional shares of common stock in us in exchange for the transfer and assignment by Yorktown of all of its rights in Carbon California (the “California Warrant”). As of February 1, 2018, we consolidate Carbon California for financial reporting purposes.

 

 

In May 2018, but effective as of October 1, 2017, Carbon California acquired 309 operated and one non-operated oil wells covering approximately 6,800 gross acres (6,600 net), and fee interests in and to certain lands, situated in the Ventura Basin, together with associated wells, pipelines, facilities, equipment and other property rights for a purchase price of $43.0 million from Seneca Resources Corporation (the “Seneca Acquisition”). We contributed approximately $5.0 million to Carbon California to fund our portion of the purchase price with the remainder funded by debt. We raised the $5.0 million through the issuance of 50,000 shares of Series B Convertible Preferred Stock, par value $0.01 per share (the “Preferred Stock”), to Yorktown.

 

Following the exercise of the California Warrant by Yorktown and the Seneca Acquisition, we own 53.92% of the voting and profits interests and Prudential Legacy Insurance Company of New Jersey and Prudential Insurance Company of America or its affiliates (“Prudential”) owns 46.08% voting and profits interest in Carbon California.   

 

Strategy

 

We continuously evaluate our portfolio of oil and gas assets and make acquisitions, investments and divestitures as part of our strategic plan. In the current environment, we are actively analyzing options such as selling assets, including potentially our Appalachian business, primarily in order to reduce indebtedness and, to a lesser extent, to fund higher value acquisition or development opportunities. Any decision to divest would be made based upon several criteria, including but not limited to the value we could obtain for such assets, the outlook for commodity prices, our expected return on invested capital and the impact on our overall leverage.

 

Our primary business objective is to create stockholder value through consistent growth in cash flows, production and reserves through development of our existing oil and gas properties and through the acquisition of complementary properties. We invest in technical staff and geological and engineering technology to enhance the value of our properties.

 

We intend to accomplish our objective by executing the following strategies:

 

●

Capitalize on the development of our oil and gas properties. Our assets consist of oil and gas properties in the Appalachian, Ventura and Illinois Basins. We aim to continue to safely optimize returns from our existing producing assets by using established technologies to maximize recoveries of in-place hydrocarbons. We expect the production from our properties will increase as we continue to develop and optimize the operation of our properties.

 

●

Acquire complementary properties. A core part of our strategy is to grow our oil and gas asset base through the acquisition of properties in the vicinity of our existing properties that feature similar reserve and production attributes. During 2018, we partnered with Prudential to finance the acquisition of producing properties in the Ventura Basin through Carbon California and with Old Ironsides to finance the acquisition of producing properties in the Appalachian Basin through Carbon Appalachia, in addition to complementary properties acquired directly by the Company. We own significant interest in Carbon California and own 100% interest in Carbon Appalachia.

 

 

●

Reduce operating costs. We plan to continue to realize economies of scale and efficiency gains and to reduce variable costs.

 

●

Replace reserves and production through execution of low risk development projects. We intend to capitalize on our regional expertise in our core operating areas to continue to optimize field development spending to create production and reserve growth. We allocate capital among opportunities in these operating areas based on risked project economics, with a view to balancing our portfolio to achieve consistent and profitable growth in production and reserves.

 

Our technical team has significant experience in drilling vertical, horizontal and directional wells. We utilize geological, drilling and completion technologies that enhance the predictability and repeatability of finding and recovering hydrocarbons throughout our asset base.

 

●

Maintain financial flexibility. We expect to fund activities and acquisitions from a combination of cash flow from operations and our bank credit facilities. In the past, we also have accessed outside capital through the use of joint ventures or similar arrangements.

 

●

Acquire and develop reserves with crude oil the primary objective in California and natural gas the primary objective in Appalachia. We believe that a diverse commodity mix provides us with commodity optionality, which allows us to direct capital spending to develop the commodity that offers the best return on investment at the time. As of December 31, 2019, our proved reserves were composed of approximately 79.8% natural gas, 18.8% oil and 1.4% natural gas liquids.

 

●

Control operating decisions and capital program. At December 31, 2019, we operated approximately 6,000 producing wells, or approximately 87.4% of the wells in which we have a working interest. This high percentage of operated wells allows us to manage the nature and timing of our capital expenditures, lease operating expenses and marketing of our 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. We have hedged a portion of our estimated future oil and natural gas production from January 1, 2020 through the end of 2022. At December 31, 2019, the estimated fair value of our commodity net derivative contracts was approximately $6.5 million.

 

●

Manage midstream assets, storage facilities and transportation firm takeaway capacity. We own natural gas gathering, storage, 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.

 

 

Operational Areas

 

Appalachian and Illinois Basins

 

As of December 31, 2019, we own working interests in approximately 6,650 gross wells (6,070 net) and royalty interests located in Illinois, Indiana, Kentucky, Ohio, Tennessee, Virginia and West Virginia, and have leasehold positions in approximately 304,700 net developed acres and approximately 1,249,000 net undeveloped acres.

 

The following table is a summary of our reserve and production data in the Appalachian and Illinois Basins as of and for the year ended December 31, 2019:

 

Estimated Total Proved Reserves

Average Net Daily

Average

Oil (MMBbls)

Natural Gas (Bcf)

Total (Bcfe)

Production (Mcfe/D)

Reserve Life (years)

1.2

430.3

437.8

59,399

20.7

 

Ventura Basin

 

As of December 31, 2019, Carbon California owns working interests in approximately 550 gross wells (530 net) located in the Ventura Basin of California and has leasehold positions in approximately 9,200 net developed acres and approximately 7,900 net undeveloped acres.

 

The following table is a summary of Carbon California’s reserve and production data in the Ventura Basin as of and for the year ended December 31, 2019:

 

Estimated Total Proved Reserves(1)																Average Net Daily				Average
Oil (MMBbls)				NGLs (MMBbls)				Natural Gas (Bcf)				Total (Bcfe)				Production (Mcfe/D)				Reserve Life (years)
	16.5				1.3				20.1				127.1				9,594				35.3

 

(1)

Represents 100% of Carbon California as of and for the year ending December 31, 2019. As of December 31, 2019, Carbon holds a 53.92% proportionate share of Carbon California. See Acquisition Highlights.

 

Commodity Price Risk Management

 

We hedge a portion of forecasted oil and gas production to reduce exposure to fluctuations in the prices of oil and natural gas and provide long-term cash flow predictability. By removing a portion of the price volatility associated with future production, we expect to mitigate, but not eliminate, the potential effects of variability in cash flow from operations due to adverse fluctuations in commodity prices.

 

We generally utilize swaps and collars designed to manage price risk.

 

 

Reserves

 

The following table summarizes our estimated quantities of proved reserves as of December 31, 2019 and 2018, inclusive of all non-controlling interests:

 

Carbon Energy Corporation

Estimated Consolidated Proved Reserves

Including Non-Controlling Interests

 

		December 31,
		2019				2018
Proved developed reserves:
Natural gas (MMcf)			444,104				450,424
Oil and liquids (MBbl)			13,908				15,808
Total proved developed reserves (MMcfe)			527,555				545,272
Proved undeveloped reserves:
Natural gas (MMcf)			6,261				4,976
Oil and liquids (MBbl)			5,180				5,013
Total proved undeveloped reserves (MMcfe)			37,338				35,054
Total proved reserves (MMcfe)			564,893				580,326
Percent developed			93.4	%			94.0	%
Average natural gas price used (per Mcf)		$	2.58			$	3.24
Average oil and liquids price used (per Bbl)		$	55.69			$	69.20

 

The estimated quantities of proved developed reserves for the non-controlling interest of Carbon California as of December 31, 2019 and 2018 are approximately 58.6 Bcfe and 47.8 Bcfe, respectively, which is approximately 10.4% and 8.2%, respectively, of total consolidated proved reserves. The estimated quantities of proved undeveloped reserves for the non-controlling interest of Carbon California as of December 31, 2019 and 2018 are approximately 17.2 Bcfe and 16.2 Bcfe, respectively, which is approximately 3.1% and 2.8%, respectively, of total consolidated proved reserves.

 

The estimated quantities of proved developed reserves for the non-controlling interests of the consolidated partnerships (not including Carbon California) as of December 31, 2019 and 2018 are approximately 3.4 Bcfe and 3.3 Bcfe, respectively, which is approximately 1.0% of total consolidated proved reserves. There were no proved undeveloped reserves associated with the non-controlling interests of the consolidated partnerships (not including Carbon California) as of December 31, 2019 and 2018.

 

The following table summarizes our estimated quantities of proved reserves, excluding non-controlling interests, as of December 31, 2019 and 2018:

 

Carbon Energy Corporation

Estimated Consolidated Proved Reserves

Excluding Non-Controlling Interests

 

		December 31,
		2019				2018
Proved developed reserves:
Natural gas (MMcf)			431,498				439,234
Oil and liquids (MBbl)			5,687				9,161
Total proved developed reserves (MMcfe)			465,618				494,199
Proved undeveloped reserves:
Natural gas (MMcf)			3,376				2,684
Oil and liquids (MBbl)			2,793				2,703
Total proved undeveloped reserves (MMcfe)			20,133				18,901
Total proved reserves (MMcfe)			485,751				513,100
Percent developed			95.9	%			96.3	%
Average natural gas price used (per Mcf)		$	2.58			$	3.24
Average oil and liquids price used (per Bbl)		$	55.69			$	69.20

 

 

The following table shows a summary of the changes in quantities of our estimated proved oil and gas reserves for the year ended December 31, 2019:

 

		Oil & Liquids				Natural Gas				Total
		MBbls				MMcf				MMcfe
Proved reserves, beginning of year			20,821				455,400				580,326
Revisions of previous estimates			(1,713	)			69,295				59,019
Extensions and discoveries			2,194				22,218				35,380
Production			(625	)			(21,436	)			(25,182	)
Demotions from proved			(1,544	)			(63,980	)			(73,247	)
Sales of reserves in-place			(45	)			(11,132	)			(11,403	)
Proved reserves, end of year			19,088				450,365				564,893

 

Preparation of Reserves Estimates

 

Our estimates of proved oil, natural gas and NGL reserves as of December 31, 2019 and 2018, were based on the average fiscal-year prices for oil, natural gas and NGL (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, 2019 and 2018, respectively). Proved developed oil, gas and NGL reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil, gas and NGL 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 in Item 8 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 our accounting records is 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, 2019 and 2018, the independent engineering firm, Cawley, Gillespie & Associates, Inc. (“CGA”) reviewed with us, technical personnel field performance and future development plans. Following these reviews, we furnished our internal reserve database and supporting data to CGA in order for them to prepare their independent reserve estimates and final report. We restrict access to our database containing reserve information to select individuals from our engineering and corporate development departments. CGA’s independent reserve estimates and final report are for our interests in the respective oil and gas properties and represents 100% of the total proved hydrocarbon reserves owned by us or 99% of the consolidated proved hydrocarbon reserves presented in our consolidated financial statements. CGA’s report does not include the hydrocarbon reserves owned by the non-controlling interests of our consolidated partnerships. We calculated the estimated reserves of the non-controlling interests of the consolidated partnerships’ oil and gas properties by multiplying CGA’s independent reserve estimates for such properties by the respective non-controlling interests in those properties.

 

Our Director of Corporate Planning and Development, Todd Habliston, is responsible for overseeing the preparation of the reserve estimates with consultations from our internal technical and accounting staff. Mr. Habliston started his career with ARCO Oil and Gas in 1983, has served as Adjunct Professor of Economics at the Colorado School of Mines, and has over 35 years of oil and gas experience in all aspects of reservoir and production engineering.  Mr. Habliston earned a B.S. in Chemical and Petroleum Refining Engineering from the Colorado School of Mines and an MBA from Purdue University. He is a registered Professional Engineer and is a member of SPE, SPEE, AAPG and API.

 

Drilling Activities

 

During 2019, we drilled two oil-related wells associated with our Carbon California assets. One well was completed in the fourth quarter of 2019 and the other well was completed in the first quarter of 2020. We completed no drilling activities in the Appalachian or Illinois Basins. Our 2019 capital expenditures consisted principally of oil-related drilling, remediation, return to production and recompletion projects in California and the optimization and streamlining of our natural gas gathering and compression facilities in Appalachia to provide more efficient and lower cost operations and greater flexibility in moving our production to markets with more favorable pricing.

 

 

The following table summarizes the number of wells drilled for the years ended December 31, 2019, 2018 and 2017. 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,
		2019								2018								2017
		Gross				Net				Gross				Net				Gross				Net
Development wells:
Productive (1)			1				1				-				-				2				1.2
Non-productive (2)			-				-				-				-				-				-
Total development wells			1				1				-				-				2				1.2
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, 2019:

 

		December 31, 2019
		Gross				Net
Gas			6,696				5,275
Oil			901				843
Total			7,597				6,118

 

Acreage

 

The following table summarizes our gross and net developed and undeveloped acreage by state as of December 31, 2019. 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, 2019
		Developed Acres								Undeveloped Acres(1)								Total Acres
		Gross				Net				Gross				Net				Gross				Net
California			11,476				9,148				8,013				7,896				19,489				17,044
Indiana			-				-				9,079				9,079				9,079				9,079
Illinois			3,758				1,879				20,225				12,613				23,983				14,492
Kentucky			10,540				10,415				78,172				76,881				88,712				87,296
Ohio			3,103				374				6,703				7,366				9,806				7,740
Tennessee			69,095				65,847				115,883				115,761				184,978				181,608
Virginia			10,541				1,385				117,768				124,569				128,309				125,954
West Virginia			1,093,266				224,837				240,103				902,748				1,333,369				1,127,585
Total			1,201,779				313,885				595,946				1,256,913				1,797,725				1,570,798

 

(1)

As of December 31, 2019, approximately 16,000, 3,000 and 2,000 net acres of undeveloped acreage are scheduled to expire by December 31, 2020, 2021 and 2022, respectively.

 

 

Production, Average Sales Prices and Production Costs

 

The following table reflects our production, average sales price, and production cost information for the years ended December 31, 2019, 2018 and 2017:

 

		Year Ended December 31,
		2019				2018(1)				2017(1)
Production data:
Natural gas (MMcf)			21,436				5,320				4,896
Oil (MBbl)			589				451				86
Natural gas liquids (MBbl)			36				33				-
Combined (MMcfe)			25,182				8,223				5,414
Gas, oil and natural gas liquids production revenue (in thousands)		$	93,841			$	48,052			$	19,511
Commodity derivative gain (in thousands)		$	3,044			$	4,894			$	2,928
Prices:
Average sales price before effects of hedging;
Natural gas (per Mcf)		$	2.63			$	3.01			$	3.12
Oil (per Bbl)		$	62.50			$	68.53			$	48.83
Natural gas liquids (per Bbl)		$	16.18			$	34.55			$	-
Average sale price after effects of hedging(2):
Natural gas (per Mcf)		$	2.80			$	2.96			$	3.25
Oil (per Bbl)			62.38			$	60.65			$	50.38
Natural gas liquids (per Bbl)		$	16.18			$	34.55			$	-
Average costs per Mcfe:
Lease operating costs		$	1.18			$	1.94			$	1.13
Transportation costs		$	0.24			$	0.54			$	0.40
Production and property taxes		$	0.22			$	0.22			$	0.24

 

(1)

The 2018 and 2017 activity shown above includes only that which is included in the consolidated financial statements. Therefore, the above represents all of Carbon’s activities for the years ended December 31, 2018 and 2017 and only the activity of Carbon California for the period February 1, 2018 through December 31, 2018. It does not include any activity for Carbon Appalachia as the OIE Membership Acquisition, which resulted in consolidation of Carbon Appalachia, did not occur until December 31, 2018.

 

(2)	Includes effect of settled commodity derivative gains and losses.

 

 

Present Activities

 

At December 31, 2019, we have successfully drilled and completed one well and we were actively completing a second well in the Ventura Basin.

 

Marketing and Delivery Commitments

 

As of December 31, 2019, we have delivery commitments of approximately 1,289,000 Btu of natural gas through February 2020 as part of a storage contract. These delivery commitments were fulfilled subsequent to year-end.

 

Through our acquisition activities, we acquired long-term firm transportation contracts that were entered into to ensure the transport of certain gas production to purchasers. Any shortfall of capacity use upon acquisition was recorded as a liability and is included in firm transportation obligations on the consolidated balance sheets of each entity.  

 

Total firm transportation volumes and related demand charges for the remaining term of these contracts at December 31, 2019 related to us are summarized in the following table:

 

Period		Dekatherms per day				Demand Charges
Jan 2020 – Mar 2020			58,871			$	0.20 - 0.62
Apr 2020 – May 2020			57,791			$	0.20 - 0.56
Jun 2020 – Oct 2020			56,641			$	0.20 - 0.56
Nov 2020 – Aug 2022			50,341			$	0.20 - 0.56
Sep 2022 – May 2027			30,990			$	0.20 - 0.21
Jun 2027 – May 2036			1,000			$	0.20

 

Major Purchasers

 

Our oil and natural gas production are generally sold on a month-to-month basis in the spot market, or in accordance with negotiated purchase contracts, and are 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.

 

For the year ended December 31, 2019, approximately 29.0% of our revenue was generated from sales to two purchasers.

 

Competition

 

We encounter competition in all aspects of 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 projects on existing properties, execute development programs, and acquire additional producing properties and leases for future development and exploration. Competitors include independent oil and gas companies, major oil and gas companies and individual producers and operators within and outside of the Appalachian, Illinois and Ventura Basins. 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 reserves and acquiring properties, we believe that we effectively compete in our and their markets. See - “Risk Factors - 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 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. In addition, unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. 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 increases 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 under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”), and the regulations promulgated under those statutes. We own an intrastate natural gas pipeline through our ownership of the Cranberry Pipeline, that provides interstate transportation and storage services pursuant to Section 311 of the NGPA, as well as intrastate transportation and storage services that are regulated by the West Virginia Public Service Commission. For qualified intrastate pipelines, FERC allows interstate transportation service “on behalf of” interstate pipelines or local distribution companies served by interstate pipelines without subjecting the intrastate pipeline to the more comprehensive NGA jurisdiction of FERC. We provide Section 311 service in accordance with a publicly available Statement of Operating Conditions filed with FERC under rates that are subject to approval by the FERC. By Letter Order issued May 15, 2013, the FERC approved the current Cranberry Pipeline rates. The May 15, 2013 Letter Order required Cranberry Pipeline to file a renewed rate petition by December 18, 2017. On November 21, 2017, FERC extended this filing deadline to December 18, 2018 in recognition of potential rate impacts of the September 2017 Acquisition. On December 12, 2018, FERC extended this filing deadline to February 19, 2019. We filed the renewed rate petition on February 19, 2019 proposing rates that were higher than the existing rates. Following settlement discussions with FERC staff, we submitted an updated rate petition on April 17, 2019 proposing to re-adopt the rates that had been in effect prior to February 19, 2019. No protests were filed, and the rates became effective on April 18, 2019.

  

In 2005, Congress enacted the Energy Policy Act of 2005 (“EPAct 2005”), which amends the NGA to make it unlawful for any entity, including non-jurisdictional producers such as Carbon, Carbon Appalachia and Carbon California, 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 FERC. EPAct 2005 also gives FERC authority to impose civil penalties for violations of the NGA up to approximately $1,300,000 per day per violation, and this amount is adjusted for inflation on an annual basis. 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 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, FERC issued rules requiring that any market participant 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 FERC, beginning on May 1, 2009. These rules are intended to increase the transparency of the wholesale natural gas markets and to assist FERC in monitoring such markets and in detecting market manipulation. In 2008, FERC issued its order on rehearing, which largely approved the existing rules, except 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, 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. We do not anticipate we will be affected any differently than other producers of natural gas.

 

Gathering service, which occurs on pipeline facilities located upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although FERC has set forth a general test for determining whether facilities perform a nonjurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities are done on a case-by-case basis. To the extent that FERC issues an order that reclassifies certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities, and depending on the scope of that decision, the costs of getting gas to point of sale locations may increase. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is often the subject of litigation, so the classification and regulation of our gathering facilities is subject to change based on future determinations by FERC, the courts or Congress. In addition, state regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

 

Additional proposals and proceedings that might affect the oil and natural gas industry are regularly considered by Congress, the states, FERC and the courts. For instance, legislation has previously been introduced in 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 FERC pursuant to the Interstate Commerce Act, the NGA, 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.

 

Regulation of Pipeline Safety and Maintenance

 

The Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established safety requirements pertaining to the design, installation, testing, construction, operation and maintenance of gas pipeline facilities, including requirements that pipeline operators develop a written qualification program for individuals performing covered tasks on pipeline facilities and implement pipeline integrity management programs. PHMSA has the statutory authority to impose civil penalties for pipeline safety violations up to a maximum of approximately $200,000 per day for each violation and approximately $2 million for a related series of violations. This maximum penalty authority established by statute will continue to be adjusted periodically to account for inflation. 

 

 

The Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“PIPES 2016 Act”), extended PHMSA’s statutory mandate under prior legislation through 2019. Congress did not pass a reauthorization bill in 2019 and the PHMSA is operating under a continuing resolution until a new bill is passed. In addition, the PIPES 2016 Act empowered PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. Additionally, in April 2016, PHMSA proposed rules that would, if adopted, strengthen existing integrity management requirements, expand assessment and repair requirements to pipelines in areas with medium population densities and extend regulatory requirements to onshore gas gathering lines that are currently exempt. The issuance of a final rule is uncertain at this time. The extension of regulatory requirements to our gathering pipelines would impose additional obligations on us and could add material costs to our and their operations. States are largely preempted by federal law from regulating pipeline safety for interstate lines, but most states are certified by the U.S. Department of Transportation to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. However, we do not expect that any such costs would be material to our financial condition or results of operations. The adoption of new or amended regulations by PHMSA or the states that result in more stringent or costly pipeline integrity management or safety standards could have a significant adverse effect on us and similarly situated midstream operators. We cannot predict what future action the DOT will take, but we do not believe that any regulatory changes will affect us in a way that materially differs from the way they will affect our or their competitors.

 

We believe our operations are in substantial compliance with all existing federal, state and local pipeline safety laws and regulations.

 

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 joint and several 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, joint 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 nonhazardous 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. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges;
	●	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 recent years, the Environmental Protection Agency (“EPA”) issued final rules to subject oil and natural gas operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured oil and natural gas wells, compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. In addition, the EPA finalized a more stringent National Ambient Air Quality Standard (“NAAQS”) for ozone in October 2015. This more stringent ozone NAAQS could result in additional areas being designated as non-attainment, which may result in an increase in costs for emission controls and requirements for additional monitoring and testing, as well as a more cumbersome permitting process. EPA anticipates promulgating final area designations under the new standard in the first half of 2018.

 

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. Based on these findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we and they produce, depressing the prices we and they receive for oil and natural gas. In addition to the regulatory efforts described above, there have also been efforts in recent years in the investment community promoting the divestment of fossil fuel equities as well as to pressure lenders and other financial services companies to limit or curtail activities with companies engaged in the extraction of fossil fuel reserves. Members of the investment community have recently increased their focus on sustainability practices, including practices related to GHGs and climate change, in the oil and natural gas industry. As a result of these efforts, our ability to access capital markets may be limited and our stock price may be negatively impacted. See “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.”

 

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 or their 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.

 

Most 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 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.

 

 

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 underground injection wells. In some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, the California Division of Oil, Gas & Geothermal Resources (“DOGGR”), renamed the Geologic Energy Management Division, or CalGEM, effective January 1, 2020, adopted regulations intended to bring California’s Class II Underground Injection Control (“UIC”) program into compliance with the federal Safe Drinking Water Act, under which some wells may require an aquifer exemption. DOGGR reviewed all active UIC projects, regardless of whether an exemption is required. DOGGR has obtained aquifer exemptions for UIC wells identified as requiring an aquifer exemption. In addition, DOGGR, now CalGEM, has undertaken a comprehensive examination of existing regulations and is in the process of issuing additional regulations with respect to certain oil and gas activities, such as management of idle wells, pipelines, underground fluid injection and well construction. CalGEM announced in November 2019 that these rule updates would include public health and safety protections for communities near oil and gas production and independent reviews of permitting processes for hydraulic fracturing and other well stimulation practices. The potential adoption of federal, state and local legislation and regulations in the areas in which we operate could restrict our or their ability to dispose of produced water gathered from drilling and production activities, which could result in increased costs and additional operating restrictions or delays.

 

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. The EPA has asserted federal regulatory authority pursuant to the federal SDWA over hydraulic fracturing involving fluids that contain diesel fuel and published permitting guidance in February 2014 for hydraulic fracturing operations that use diesel fuel in fracturing fluids in those states in which EPA is the permitting authority. In recent years, the EPA has issued final regulations under the federal CAA establishing performance standards for completions of hydraulically fractured oil and natural gas wells, compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment, and also finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Many producing states, cities and counties 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. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. The scientific community and regulatory agencies at all levels are studying the possible linkage between oil and gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. If legislation or regulations are adopted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have a significant impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, will result in additional expense and delay in our operations. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our or their reserves. See “Environmental legislation and regulatory initiatives, including those relating to hydraulic fracturing and underground injection could result in increased costs and additional operating restrictions or delays.”

 

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 are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards.

 

 

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, 2019, our workforce consisted of 215 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.

  

Offices

 

Our executive offices are located at 1700 Broadway, Suite 1170, Denver, Colorado 80290. We maintain offices in Lexington, Kentucky and Santa Paula, California 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 our lenders 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 wells 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.

 

MMBbls means one million barrels of crude oil or other liquid hydrocarbons.

 

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.

 

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 10.0%, 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

 

We are subject to the information and reporting requirements of the Exchange Act and will file annual, quarterly and current reports, proxy statements and other information with the SEC.

 

Our SEC filings, including this Annual Report on Form 10-K, are available to you through our website at http://www.carbonenergycorp.com, free of charge, after we file them with the SEC. Our filings with the SEC are also available on the SEC’s website at http://www.sec.gov. You can request copies of these documents, for a copying fee, by writing to the SEC. We intend to furnish our stockholders with annual reports containing financial statements audited by our independent auditors. We intend to use our website as a regular means of disclosing material non-public information and for complying with disclosure obligations under Regulation FD promulgated by the SEC.  Such disclosures will be included on the website under the heading “Investor Relations.”

 

Information contained on our website is not incorporated by reference into this Annual Report on Form 10-K.

 

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. Investing in our common stock involves a high degree of risk. If any of the following risks actually occur, they may materially and adversely affect our business, financial condition, cash flows, and results of operations. In this event, the trading price of our common stock could decline, and you could lose part or all of your investment. 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.

 

 

Risks Related to Our Business

 

Oil, natural gas and NGL prices and differentials are highly volatile. Declines in commodity prices, especially steep declines in the price of oil and natural gas, have adversely affected, and in the future will adversely affect, our financial condition and results of operations, cash flow, access to the capital markets and ability to grow.

 

The oil, natural gas and NGL markets are highly volatile, and we cannot predict future oil, natural gas or NGL prices. Prices for oil, natural gas and NGLs may fluctuate widely in response to relatively minor changes in the supply of and demand for oil, natural gas and NGLs, market uncertainty and a variety of additional factors that are beyond our control, such as:

 

●

domestic and foreign supply of and demand for oil, natural gas and NGLs;

 

●

market prices of oil, natural gas and NGLs;

 

●

level of consumer product demand;

 

●

overall domestic and global political and economic conditions;

 

●

political and economic conditions in producing countries, including those in the Middle East, Russia, South America and Africa;

 

●

global or national health concerns, including the outbreak of pandemic or contagious disease, such as the recent coronavirus, which may reduce demand for crude oil, natural gas and NGLs because of reduced global or national economic activity;

 

●

actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;

 

●

weather conditions;

 

●

impact of the U.S. dollar exchange rates on commodity prices;

 

●

technological advances affecting energy consumption and energy supply;

 

●

domestic and foreign governmental regulations and taxation;

 

●

impact of energy conservation efforts;

 

●

capacity, cost and availability of oil and natural gas pipelines, processing, gathering and other transportation facilities and the proximity of these facilities to our wells;

 

●

the ability to export liquid natural gas outside of the United States; and

 

●

price and availability of alternative fuels.

 

Oil, natural gas and NGL prices do not necessarily fluctuate in direct relationship to each other. Because oil, natural gas and NGL accounted for approximately 19%, 80% and 1% of our estimated proved reserves as of December 31, 2019, respectively, and approximately 14%, 85% and 1% of our 2019 production on an Mcfe basis, respectively, our financial results will be sensitive to movements in oil and natural gas prices.

 

In the past, prices of oil and natural gas have been volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2019, the monthly average NYMEX WTI spot price ranged from a high of $66.30 per Bbl in April to a low of $46.54 per Bbl in January while the monthly average Henry Hub natural gas price ranged from a high of $4.25 per MMBtu in March to a low of $1.75 per MMBtu in December. Since December 31, 2019, prices have declined, with the NYMEX WTI spot price on March 16, 2020 at $28.70 per Bbl and the Henry Hub natural gas price on March 16, 2020 at $1.82 per MMBtu. Price discounts or differentials between NYMEX WTI spot prices and what we actually receive are also historically volatile.

 

Due to the volatility of commodity prices, we are unable to predict future potential movements in the market prices for natural gas, NGLs and oil and thus cannot predict the ultimate impact of prices on our operations.

 

Our production in the Ventura Basin received an approximate 9.7% premium to the NYMEX WTI benchmark price during 2019. A reduction in this premium would reduce the relative price advantage we receive for a substantial portion of our production in the Ventura Basin.

 

 

Our revenue, profitability and cash flow depend upon the prices and demand for oil, NGLs and natural gas. A drop in prices would significantly affect our financial results and impede our growth. In particular, a significant or prolonged decline in oil, NGL or natural gas prices will negatively impact:

 

●

the value of our reserves, because declines in oil, NGL and natural gas prices would reduce the amount of oil, NGLs and natural gas that we can produce economically;

 

●

the amount of cash flow available for capital expenditures;

 

●

our ability to replace our production and future rate of growth;

 

●

our ability to borrow money or raise additional capital and our cost of such capital; and

 

●

our ability to meet our financial obligations.

 

Historically, higher oil, NGL and natural gas prices generally result in increased demand and prices for drilling equipment, crews and associated supplies, equipment and services, as well as higher lease operating expenses and increased end-user conservation or conversion to alternative fuels. However, commodity price declines do not result in similarly rapid declines of costs associated with drilling. Accordingly, a high cost environment could adversely affect our ability to pursue our drilling program and our results of operations.

 

The refining industry may be unable to absorb rising U.S. oil and condensate production; in such a case, the resulting surplus could depress prices and restrict the availability of markets, which could materially and adversely affect our results of operations.

 

Absent an expansion of U.S. refining and export capacity, rising U.S. production of oil and condensates could result in a surplus of these products in the U.S., which would likely cause prices for these commodities to fall and markets to constrict. Although U.S. law was changed in 2015 to permit the export of oil, exports may not occur if demand is lacking in foreign markets or the price that can be obtained in foreign markets does not support associated export capacity expansions, transportation and other costs. In such circumstances, the returns on our capital projects would decline, possibly to levels that would make execution of our drilling plans uneconomical, and a lack of market for our products could require that we shut in some portion of our production. If this were to occur, our production and cash flow could decrease, or could increase less than forecasted, which could have a material adverse effect on our cash flow and profitability.

 

Carbon Energy Corporation is a holding company with no oil and gas operations of its own, and Carbon Energy Corporation depends on our subsidiaries for cash to fund certain of its operations and expenses.

 

Carbon Energy Corporation’s operations are conducted entirely through our subsidiaries, and our ability to generate cash to meet our operating obligations is dependent on the earnings and the receipt of funds from our subsidiaries through distributions or intercompany loans. Carbon Energy Corporation’s subsidiaries’ ability to generate adequate cash depends on a number of factors, including development of reserves, successful acquisitions of complementary properties, advantageous drilling conditions, oil and natural gas prices, compliance with all applicable laws and regulations and other factors.

 

  

We do not solely control certain investments.

 

We have no significant assets other than our ownership interest in entities that own and operate oil, natural gas, and NGLs interests. More specifically:

 

●

Carbon California is managed by its respective governing board. Our ability to influence decisions with respect to its operations varies depending on the amount of control we exercise under the applicable governing agreement;

 

●

We do not control the amount of cash distributed by Carbon California. Further, debt facilities at Carbon California and our other subsidiaries currently restrict distributions. We may influence the amount of cash distributed through our board seats on such entity’s governing board, but may not ultimately be successful in such efforts;

  

●

We may not have the ability to unilaterally require certain of the entities in which we own interests to make capital expenditures, and such entities may require us to make additional capital contributions to fund operating and maintenance expenditures, as well as to fund expansion capital expenditures, which would reduce the amount of cash otherwise available for dividend payments by us or require us to incur additional indebtedness;

 

●

The entities in which we own interests may incur additional indebtedness without our consent, which debt payments would reduce the amount of cash that might otherwise be available for distributions;

 

●

Certain of our assets are operated by entities that we do not control; and

 

●

The third-party operator of certain of the assets held by us or Carbon California and the identity of our partners could change, in some cases without our consent. Our dependence on the operators of such assets and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could have a material adverse effect on the realization of our targeted returns on capital or lead to unexpected future costs.

 

Our level of indebtedness may increase and reduce our financial flexibility.

 

We have a $500.0 million bank credit facility with Prosperity Bank (formerly known as LegacyTexas Bank), as the administrative agent, and a syndicate of financial institutions, as lenders. The credit facility has a current borrowing base of $72.0 million, the outstanding balance of which was approximately $69.2 million at December 31, 2019 and $71.2 million at March 16, 2020. We have $15.0 million associated with a term loan under the same facility, which balance was approximately $5.8 million at December 31, 2019 and $3.3 million at March 16, 2020. We have notes payable to Old Ironsides, the balance of which was approximately $25.7 million as of December 31, 2019 and March 16, 2020.

 

Carbon California sold certain Senior Secured Revolving Notes (the “Carbon California Senior Revolving Notes”) to Prudential Legacy Insurance Company of New Jersey and Prudential Insurance Company of America with a revolving borrowing capacity of $45.0 million. There was approximately $33.0 million of indebtedness outstanding thereunder as of December 31, 2019 and $36.0 million as of March 16, 2020. We are not a guarantor of the Senior Secured Revolving Notes.

 

Carbon California also issued subordinated notes (the “Subordinated Notes”) to Prudential Capital Energy Partners the balance of which was $13.0 million as of December 31, 2019 and March 16, 2020.

 

We may incur significant indebtedness in the future in order to make acquisitions or to develop our properties.

 

Our level of indebtedness could affect our operations in several ways, including the following:

 

●

a significant portion of our cash flows could be used to service our indebtedness;

 

●

a high level of debt would increase our vulnerability to general adverse economic and industry conditions;

 

●

the covenants contained in the agreements governing our outstanding indebtedness limit our ability to borrow additional funds, dispose of assets, pay dividends, and make certain investments;

 

●

a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;

 

 

●

our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

 

●

a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; and

 

●

a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate, or other purposes.

 

A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, commodity prices, and financial, business, and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, borrowings, or equity financing may not be available to pay or refinance such debt. Factors that may affect our ability to raise cash through a potential offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets, and our performance at the time we need capital.

 

We may not be able to generate enough cash flow to meet our debt obligations or fund our other liquidity needs.

 

At December 31, 2019, our debt consisted of approximately $69.2 million in borrowings under credit facility, $5.8 million associated with a term loan, approximately $25.7 million associated with the Old Ironsides Notes, approximately $33.0 million outstanding under the Carbon California Senior Revolving Notes and approximately $13.0 million outstanding under the Subordinated Notes. In addition to interest expense and principal on our non-current 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 non-current 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; or

 

●

restructuring or refinancing debt.

 

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 and may reduce our ability to pay dividends on our common stock. The formation of joint ventures or other similar arrangements to finance operations may result in dilution of our interest in the properties affected by such arrangements.

 

 

A deterioration in general economic, business or industry conditions would materially adversely affect our results of operations, financial condition and ability to pay dividends on our common stock.

 

If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could materially decrease, which could impact the price at which oil, natural gas and NGLs from our properties are sold, affect the ability of vendors, suppliers and customers associated with our properties to continue operations and ultimately materially adversely impact our results of operations, financial condition and ability to pay dividends on our common stock.

 

Beginning in February 2020, oil and natural gas prices have experienced record declines and are currently at record low levels in response to dramatic supply and demand uncertainty caused by the coronavirus pandemic and the recent announcement of planned production increases by Saudi Arabia. For example, the price of oil fell approximately 20% on March 9, 2020 due to Saudi Arabia's decision to increase its production to record levels. As of March 16, 2020, the NYMEX WTI spot price was $28.70 per Bbl and the Henry Hub natural gas price was $1.82 per MMBtu. We cannot anticipate whether or when production will return to normalized levels, and oil and natural gas prices could remain at current levels or decline further, for an extended period of time.

 

The agreements governing our indebtedness contain restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.

 

Our credit agreement contains restrictive covenants that limit our ability to, among other things:

 

●

incur additional debt;

  

●

incur additional liens;

 

●

sell, transfer or dispose of assets;

 

●

merge or consolidate, wind-up, dissolve or liquidate;

 

●

make dividends and distributions on, or repurchases of, equity;

 

●

make certain investments;

 

●

enter into certain transactions with our affiliates;

 

●

enter into sales-leaseback transactions;

 

●

make optional or voluntary payment of debt;

 

●

change the nature of our business;

 

●

change our fiscal year to make changes to accounting treatments or reporting practices;

 

●

amend constituent documents; or

 

●

enter into certain hedging transactions.

 

In addition, our credit agreement requires us to maintain certain financial ratios and tests. The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures, or withstand a continuing or future downturn in our business.

 

 

If we are unable to comply with the restrictions and covenants in our credit agreement, there could be an event of default under the terms of such agreement, which could result in an acceleration of repayment.

 

If we are unable to comply with the restrictions and covenants in our credit agreements, there could be an event of default. Our ability to comply with these restrictions and covenants, including meeting the financial ratios and tests, may be affected by events beyond our control. As a result, we cannot assure you that we will be able to comply with these restrictions and covenants or meet such financial ratios and tests. In the event of a default under our credit agreements, the lenders could terminate their commitments to lend or accelerate the loans and declare all amounts borrowed due and payable. If any of these events occur, our assets might not be sufficient to repay in full all of our outstanding indebtedness and we may be unable to find alternative financing. Even if we could obtain alternative financing, it might not be on terms that are favorable or acceptable to us. Additionally, we may not be able to amend our credit agreements or obtain needed waivers on satisfactory terms.

 

Our borrowings under our credit agreement and the Carbon California Senior Revolving Notes expose us to interest rate risk.

 

Our results of operations are exposed to interest rate risk associated with borrowings under our credit agreement, which bear interest at a rate elected by us that is based on the prime, London Interbank Offered Rate (“LIBOR”), or federal funds rate plus margins ranging from 0.50% to 3.75% depending on the type of loan used and the amount of the loan outstanding in relation to the borrowing base. As of March 16, 2020, there was approximately $71.2 million outstanding under our credit agreement. In addition, interest on borrowings under the Carbon California Senior Revolving Notes is payable quarterly and accrues at a rate per annum equal to either the prime rate plus an applicable margin of 4.00% or the LIBOR rate plus an applicable margin of 5.00% at our option. As of March 16, 2020, there was approximately $36.0 million outstanding under the Carbon California Senior Revolving Notes. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.

 

Any significant reduction in our borrowing base under our credit agreement or the Carbon California Senior Revolving Notes as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

 

Under our credit agreement, which as of March 16, 2020, provides for a $72.0 million borrowing base, and the Carbon California Senior Revolving Notes, which as of March 16, 2020, provides for a $45.0 million borrowing base, we are subject to collateral borrowing base redeterminations based on our proved reserves. We agreed to monthly borrowing base reductions through May 1, 2020 in connection with the recent amendment to our credit agreement. 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. Since December 31, 2019, prices have declined, with the NYMEX WTI spot price on March 16, 2020 at $28.70 per Bbl and the Henry Hub natural gas price on March 16, 2020 at $1.82 per MMBtu. Our next scheduled borrowing base redetermination is May 1, 2020, and if these lower prices persist, our borrowing base may be reduced materially. Furthermore, our lenders have the right at any time to request a special determination of the borrowing base. Any significant reduction in our borrowing base as a result of such borrowing base redeterminations or otherwise may require us to prepay a portion of our borrowings under the credit agreement and may otherwise negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial condition, results of operations, and cash flows.

 

Changes in the method of determining the LIBOR, or the replacement of LIBOR with an alternative reference rate, may adversely affect interest expense related to outstanding debt.

 

Amounts drawn under our current debt agreements, including our credit agreement, may bear interest at rates based on the LIBOR. On July 27, 2017, the Financial Conduct Authority in the United Kingdom announced that it would phase out LIBOR as a benchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. We have not yet pursued any technical amendment to our credit agreement or other contractual alternative to address this matter and are currently evaluating the impact of the potential replacement of the LIBOR interest rate. In addition, the overall financial markets may be disrupted as a result of the phase-out or replacement of LIBOR. Uncertainty as to the nature of such potential phase-out and alternative reference rates or disruption in the financial market could have a material adverse effect on our financial condition, results of operations and cash flows.

  

Our estimates of proved reserves at December 31, 2019 and 2018 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, 2019 and 2018 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. In addition, we based the discounted future net cash flows from our proved reserves on the twelve-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net cash flows from our properties will be affected by factors such as the actual prices we receive for oil, NGLs and natural gas, the amount, timing and cost of actual production and changes in governmental regulations or taxation.

 

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 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 proved reserves.

 

Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of reserves and assumptions concerning future commodity prices, production levels, estimated ultimate recoveries, and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates, and the timing of development expenditures may be incorrect. Our estimates of proved reserves and related valuations as of December 31, 2019 and 2018 are based on proved reserve reports prepared by CGA, an independent engineering firm. CGA conducted a well-by-well review of all our properties for the periods covered by its proved reserve reports using information provided by us. Over time, we may make material changes to proved reserve estimates taking into account the results of actual drilling, testing, and production. Also, certain assumptions regarding future commodity prices, production levels, and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of proved reserves, the economically recoverable quantities of reserves attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of reserves we ultimately recover being different from our estimates.

 

The estimates of proved reserves as of December 31, 2019 and 2018 included in this annual report were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12 months ended December 31, 2019 and 2018, respectively, in accordance with the SEC guidelines applicable to reserve estimates for these periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved acreage. The reserve estimates represent our net revenue interest in such properties.

 

The present value of future net cash flows from estimated proved reserves is not necessarily the same as the current market value of estimated proved oil and natural gas reserves. We base the current market value of estimated proved reserves on prices and costs in effect on the day of the estimate. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:

 

●

the actual prices we receive for oil and natural gas;

 

●

our actual operating costs in producing oil and natural gas;

 

●

the amount and timing of actual production;

 

●

the amount and timing of our capital expenditures;

 

●

supply of and demand for oil and natural gas; and

 

●

changes in governmental regulations or taxation.

 

 

The timing of our production and incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves and thus their actual present value.  In addition, the 10.0% discount factor we use when calculating discounted future net cash flows in compliance with accounting principles generally accepted in the United States (“GAAP”) may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.

 

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, including capitalizing the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves. The average depletion rate per Mcfe of production associated with our reserves was $0.56 and $0.89 for 2019 and 2018, respectively. Total depletion expense for oil and natural gas properties was approximately $14.1 million and $7.3 million for 2019, and 2018, respectively.

 

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 10.0%. 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 GAAP we are required to perform a ceiling test each quarter. We did not recognize an impairment for the years ended December 31, 2019 or 2018. Impairment charges do not affect cash flows from operating activities but do adversely affect earnings and stockholders’ equity.

 

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, GAAP requires us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments, which 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. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and therefore requires a write-down. 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.

 

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. Our cash used in investing activities related to acquisition, development and exploration expenditures was approximately $8.0 million and $70.4 million in 2019 and 2018, respectively. We contribute our proportionate share, as a holder of Class A Units that require capital contributions.

 

 

Due to the recent developments surrounding the COVID-19 virus and relative pricing volatility, we are currently evaluating the 2020 capital program. The budget will be highly dependent on prices that we receive for our oil and natural gas sales. We intend to finance capital expenditures through cash on hand, cash flow from operations, and, to the extent available, borrowings under bank credit facilities. Our cash flows from operations and access to capital are subject to several variables, including:

 

●

proved reserves;

 

●

the volume of hydrocarbons we are able to produce from existing wells;

 

●

the prices at which our production is sold;

 

●

the levels of our operating expenses; and

 

●

our ability to acquire, locate, and produce new reserves.

 

Our financing needs, especially regarding potential acquisitions, may exceed those resources. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we may be required to seek additional sources of capital, which may include the issuance of debt or equity securities, sale of assets, delays in planned development activities or the use of outside capital through equity investees or similar arrangements.

 

Our business and operating results can be harmed by factors such as the availability, terms, and cost of capital, increases in interest rates, or a reduction in our credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling, and place us at a competitive disadvantage. In addition, our ability to access the private and public debt or equity markets is dependent upon several factors outside our control, including oil and natural gas prices as well as economic conditions in the financial markets. Disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance operations. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.

 

If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our reserves and cash flow, or may be otherwise unable to implement our development plan, complete acquisitions, or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues, and results of operations. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies and related cost savings.

 

Carbon California may require its members, including us, to make additional capital contributions to it. If we fail to make a required capital contribution to Carbon California, (i) we would be considered a defaulting member, (ii) we would lose our representative on the Board of Directors, and (iii) Prudential would have the option to pay our pro rata portion of the capital contribution and receive the pro rata share of Class A Units in Carbon California that we otherwise would have received.

 

Our identified field development projects are scheduled for development only if oil and gas prices warrant development over a substantial number of years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their completion.

 

At an appropriate level of oil and natural gas prices, we have a multi-year inventory of field development projects on existing acreage. Our ability to develop these projects depends on several uncertainties, including the availability of capital, infrastructure, inclement weather, regulatory changes and approvals, commodity prices, lease expirations and expected capital costs.

 

 

Further, our identified potential projects are in various stages of evaluation, ranging from those that are ready to complete to those that will require substantial additional analysis of data. We cannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas reserves in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of reliable technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas reserves will be present or, if present, whether oil or natural gas reserves will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas reserves exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations, or producing fields will be applicable to our projects. Further, initial production rates reported by us or other operators in the Appalachian Basin and Ventura Basin may not be indicative of future or long-term production rates.

 

Because of these uncertainties, we do not know if the potential projects we have identified will ever be completed or if we will be able to produce oil or natural gas reserves from these or any other potential projects. As such, our actual development activities may materially differ from those presently identified, which could adversely affect our business, financial condition, and results of operations.

 

Certain of our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. Failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

 

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Any reduction in our current drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. We cannot assure you that we will have the liquidity to deploy these rigs when needed, or that commodity prices will warrant operating such a drilling program. Any such losses of leases could materially and adversely affect the growth of our asset base, cash flows, and results of operations.

 

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 have made, and expect to make in the future, substantial capital expenditures in our business and operations for the development, production, exploration, and acquisition of reserves. We may not have sufficient resources to undertake our exploration, development, and production activities. In addition, 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. Our decision 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 “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 proved reserves.” The costs of exploration, exploitation, and development activities are subject to numerous uncertainties beyond our control and increases in those costs can adversely affect the economics of a project. 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:

 

●

high costs, shortages or delivery delays of drilling rigs, equipment, labor or other services;

 

●

unexpected operational events and drilling conditions;

 

●

sustained depressed oil and natural gas prices and further reductions in oil and natural gas prices;

 

●

limitations in the market for oil and natural gas;

 

●

problems in the delivery of oil and natural gas to market (see “Our business depends in part 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.”);

  

●

adverse weather conditions;

 

●

facility or equipment malfunctions;

 

●

equipment failures or accidents;

 

●

title problems;

 

●

pipe or cement failures;

 

●

casing collapses;

 

●

compliance with environmental and other governmental requirements;

 

●

delays in obtaining, extending or renewing necessary permits or the inability to obtain, extend or renew such permits at all;

 

●

environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;

 

●

lost or damaged oilfield drilling and service tools;

 

●

unusual or unexpected geological formations;

 

●

loss of drilling fluid circulation;

 

●

pressure or irregularities in formations;

 

●

fires, blowouts, surface craterings and explosions; and

 

●

uncontrollable flows of oil, natural gas or well fluids.

 

 

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.

 

Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

 

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. Risks that we may face while drilling include, but are not limited to, failing to land our wellbore in the desired drilling zone, not staying in the desired drilling zone while drilling horizontally through the formation, not running our casing the entire length of the wellbore, and not being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we may face while completing our wells include, but are not limited to, not being able to fracture stimulate the planned number of stages, not being able to run tools the entire length of the wellbore during completion operations, and not successfully cleaning out the wellbore after completion of the final fracture stimulation stage. In addition, to the extent we engage in horizontal drilling, those activities may adversely affect our ability to successfully drill in one or more of our identified vertical drilling locations.

 

Our experience with horizontal drilling utilizing the latest drilling and completion techniques is limited. Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or commodity prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.

 

A significant portion of our business is conducted in basins with established production histories.

 

The Appalachian and Ventura Basins are mature oil and natural gas production regions that have experienced substantial exploration and development activity for many years. Because many oil and natural gas prospects in this region have already been drilled, additional prospects of sufficient size and quality could be more difficult to identify. We cannot assure you that our future development activities in these 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.

 

Our operations are substantially dependent on the availability of water and electricity. Restrictions on our ability to obtain water, or increasing prices or shortages of electricity, particularly in California, may have an adverse effect on our financial condition, results of operations, and cash flows.

 

Water and electricity are essential components of oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. As a result of severe drought in parts of California, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect the availability of local water supply. Additionally, in recent years, shortages of electricity have resulted in increased costs for consumers and certain interruptions in service. California has experienced rolling blackouts due to excessive demand on the electrical grid or as precautionary measures against the risk of wildfire in the past because of unexpectedly high temperatures. If we are unable to obtain water to use in our operations from local sources or we experience electricity blackouts, we may be unable to economically produce our reserves or run our operations, which could have an adverse effect on our financial condition, results of operations, and cash flows.

 

We may face unanticipated water and other waste disposal costs.

 

We may be subject to regulation that restricts our ability to discharge water produced as part of our natural gas production operations. Productive zones frequently contain water that must be removed for the oil and natural gas to produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether we can produce natural gas in commercial quantities. The produced water must be transported from the production site and injected into disposal wells. The capacity of the disposal wells we own may not be sufficient to receive all the water produced from our wells and may affect our ability to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability.

 

 

Where water produced from our projects fails to meet the quality requirements of applicable regulatory agencies, our wells produce water in excess of the applicable volumetric permit limits, the disposal wells fail to meet the requirements of all applicable regulatory agencies, or we are unable to secure access to disposal wells with sufficient capacity to accept all of the produced water, we may be required to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur:

 

●

we cannot obtain future permits from applicable regulatory agencies;

 

●

water of lesser quality or requiring additional treatment is produced;

 

●

our wells produce excess water;

 

●

new laws and regulations require water to be disposed in a different manner; or

 

●

costs to transport the produced water to the disposal wells increase.

 

Our insurance may not protect us against all the operating risks to which our business is exposed.

 

The crude oil and natural gas business involves numerous operating hazards such as well blowouts, mechanical failures, explosions, uncontrollable flows of crude oil, natural gas or well fluids, fires, formations with abnormal pressures, hurricanes, flooding, pollution, releases of toxic gas and other environmental hazards and risks, which can result in (i) damage to or destruction of wells and/or production facilities, (ii) damage to or destruction of formations, (iii) injury to persons, (iv) loss of life, or (v) damage to property, the environment or natural resources. While we carry general liability, control of well, and operator’s extra expense coverage typical in our industry, we are not fully insured against all risks incidental to our business. Environmental incidents resulting from our operations could defer revenue, increase operating costs and/or increase maintenance and repair capital expenditures.

 

Many of our operations are currently conducted in locations that may be at risk of damage from fire, mudslides, earthquakes or other natural disasters.

 

Carbon California currently conducts operations in California near known wildfire and mudslide areas and earthquake fault zones. Certain of Carbon California’s operations were temporarily halted in December 2017 due to the wildfires in southern California. A future natural disaster, such as a fire, mudslide or an earthquake, could cause substantial delays in our operations, damage or destroy equipment, prevent or delay transport of production and cause us to incur additional expenses, which would adversely affect our business, financial condition and results of operations. In addition, our facilities would be difficult to replace and would require substantial lead time to repair or replace. The insurance we maintain against earthquakes, mudslides, fires and other natural disasters would not be adequate to cover a total loss of our facilities, may not be adequate to cover our losses in any particular case and may not continue to be available to us on acceptable terms, or at all.

 

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 these safety procedures, there are many risks involved in hydraulic fracturing that could result in liability to us. In addition, our liability for environmental hazards may include conditions created by the previous owner of properties that we purchase or lease.

 

We have entered into natural gas and oil derivative contracts and may in the future enter into additional commodity derivative contracts for a portion of our production, which may result in future cash payments or prevent us from receiving the full benefit of increases in commodity prices.

 

We use commodity derivative contracts to reduce price volatility associated with certain of our natural gas and oil sales. Under these contracts, we receive a fixed price per MMbtu of natural gas/Bbl of oil and pay a floating market price per MMbtu/Bbl of natural gas/oil to the counterparty based on Henry Hub, NYMEX WTI or Brent pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. The extent of our commodity price exposure is related largely to the effectiveness and scope of our commodity derivative contracts. For example, our commodity derivative contracts are based on quoted market prices, which may differ significantly from the actual prices we realize in our operations for oil. In addition, our credit agreements limit the aggregate notional volume of commodities that can be covered under commodity derivative contracts we enter into and, as a result, we will continue to have direct commodity price exposure on the unhedged portion of our production volumes. Our policy has been to hedge a significant portion of our estimated oil and natural gas production. However, our price hedging strategy and future hedging transactions, beyond the requirement of our credit facilities, will be determined at our discretion. The prices at which we hedge our production in the future will be dependent upon commodity prices at the time we enter into these transactions, which may be substantially higher or lower than current commodity prices. Accordingly, our price hedging strategy may not protect us from significant declines in commodity prices received for our future production, whether due to declines in prices in general or to widening differentials we experience with respect to our products. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the last few years, which would result in our revenues becoming more sensitive to commodity price changes.

 

In addition, our actual future production may be significantly higher or lower than we estimate at the time we enter into commodity derivative contracts for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the notional amount of our commodity derivative contracts, we might be forced to satisfy all or a portion of our commodity derivative contracts without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, substantially diminishing our liquidity. There may be a change in the expected differential between the underlying commodity price in the commodity derivative contract and the actual price received, which may result in payments to our derivative counterparty that are not offset by our receipt of payments for our production in the field. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our commodity derivative contracts.

 

Our commodity derivative contracts expose us to counterparty credit risk.

 

Our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the contract and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

 

 

During periods of declining commodity prices, our derivative contract receivable positions generally increase, which increases our counterparty credit exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our commodity derivative contracts.

 

The inability of our derivative contract counterparties to meet their obligations may adversely affect our financial results.

 

We currently have two derivative contract counterparties and this concentration may impact our overall credit risk in that the counterparties may be similarly affected by changes in economic or other conditions. The inability or failure of our derivative contract counterparties to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial condition and results of operations.

 

Our business depends in part 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 and processing systems owned by third parties. Since we do not own or operate these pipelines or other facilities, their continuing operation in their current manner is not within our control. 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, transportation or processing 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. If any of these third party pipelines and other facilities become partially or fully unavailable to transport natural gas or oil, or if the gas quality specifications for the natural gas gathering or transportation pipelines or facilities change so as to restrict our ability to transport natural gas on those pipelines or facilities, our revenues and cash available for distribution could be adversely affected.

 

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. Rather, we rely upon the judgment of oil and natural gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. 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. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we may suffer a financial loss. 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, our 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.

 

 

Conservation measures and technological advances could reduce demand for oil and natural gas.

 

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy-generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may materially adversely affect our business, financial condition, results of operations and ability to pay dividends on our common stock.

 

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.

 

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national, or international basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local, and other laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing reserves.

 

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, and results of operations could be materially adversely affected.

 

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, including Patrick McDonald, our Chief Executive Officer, Mark Pierce, our President, and 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.

 

In addition, there is competition within our industry for experienced technical personnel and certain other professionals, which could increase the costs associated with identifying, attracting and retaining such personnel. If we cannot identify, attract, develop and retain our technical and professional personnel or attract additional experienced technical and professional personnel, our ability to compete could be harmed.

 

 

Due to our lack of asset and geographic diversification, adverse developments in our operating areas would reduce our ability to pay dividends on shares of our common stock.

 

A substantial majority of our assets are located in the Ventura Basin in California and Appalachian Basin. An adverse development in the oil and gas business of these geographic areas, including those resulting from the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by and costs associated with governmental regulation, processing or transportation capacity constraints, market limitations, water shortages or other weather related conditions, interruption of the processing or transportation of oil, NGLs or natural gas and changes in regional and local political regimes and regulations, would have a significantly greater impact on our results of operations and cash available for dividend payments on shares of our common stock than if we maintained more diverse assets and locations.

 

We may be subject to risks in connection with acquisitions of properties and may be unable to successfully integrate acquisitions.

 

There is intense competition for acquisition opportunities in our industry and 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 acquisitions or do so on commercially acceptable terms. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently operate, which could result in unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel, and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with these regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities, and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Completed acquisitions could require us to invest further in operational, financial, and management information systems and to attract, retain, motivate, and effectively manage additional employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our results of operations and growth. Our financial condition and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

 

Any acquisition involves potential risks, including, among other things:

 

●

the validity of our assumptions about estimated proved reserves, future production, commodity prices, revenues, capital expenditures, operating expenses, and costs;

 

●

an inability to obtain satisfactory title to the assets we acquire;

 

	●	a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;
	●	a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;

 

●

the assumption of unknown liabilities, losses, or costs for which we obtain no or limited indemnity or other recourse;

 

●

the diversion of management’s attention from other business concerns;

 

●

an inability to hire, train, or retain qualified personnel to manage and operate our growing assets; and

 

●

the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill, or other intangible assets, asset devaluation, or restructuring charges.

 

 

Our ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond our control, and in certain cases we may be required to retain liabilities for certain matters.

 

From time to time, we may sell an interest in an asset for the purpose of assisting or accelerating the asset’s development. In addition, we regularly review our property base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Various factors could materially affect our ability to dispose of such interests or nonstrategic assets or complete announced dispositions, including the receipt of approvals of governmental agencies or third parties and the availability of purchasers willing to acquire the interests or purchase the nonstrategic assets on terms and at prices acceptable us.

 

Sellers typically retain certain liabilities or indemnify buyers for certain pre-closing matters, such as matters of litigation, environmental contingencies, royalty obligations and income taxes. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.

 

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire, or obtain protection from sellers against such liabilities.

 

Acquiring oil and natural gas properties requires us to assess reservoir and operating characteristics, including recoverable reserves, development and operating costs, and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

 

 

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.

 

The recent spread of COVID-19, or the novel coronavirus, and measures taken to mitigate the impact of the COVID-19 pandemic, are adversely affecting our business, operations and financial condition.

 

Our business is being adversely affected by the COVID-19 pandemic and measures being taken to mitigate its impact. As the coronavirus pandemic and government responses are rapidly evolving, the extent of the impact on domestic exploration and production companies remains unknown. We are experiencing a sharp and rapid decline in the demand for the oil and natural gas we produce as the U.S. and global economy, as well as commodity prices, are being negatively impacted as economic activity is curtailed in response to the COVID-19 pandemic. Official restrictions on non-essential activities have recently been introduced in California, which may impact our production activities, and the introduction of similar measures elsewhere, including in the Appalachian Basin, may further adversely affect us. In addition, our reliance on third-party suppliers, contractors, and service providers exposes us to possibility of delay or interruption of our operations. We anticipate that our business, financial condition and results of operations may be materially and adversely impacted as a result of these developments.

 

A terrorist attack or armed conflict could harm our business.

 

Terrorist activities, anti-terrorist activities and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our operators’ services and causing a reduction in our revenues. Oil and natural gas facilities, including those of our operators, could be direct targets of terrorist attacks, such as the September 2019 attacks on a Saudi Arabian crude oil processing plant, and if infrastructure integral to our operators is destroyed or damaged, they may experience a significant disruption in their operations. Our insurance may not protect us against such occurrences. Any such disruption could materially adversely affect our financial condition, results of operations and cash available to pay dividends on our common stock.

 

Our business could be materially and adversely affected by security threats, including cybersecurity threats, and other disruptions.

 

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. We depend on digital technology to estimate quantities of oil, natural gas and NGL reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our customers, employees and third-party partners. As an oil and gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts and acts of war. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Costs for insurance may also increase as a result of security threats, and some insurance coverage may become more difficult to obtain, if available at all. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations and cash flows.

 

Cybersecurity attacks in particular are becoming more sophisticated and coordinated in their attempts to access other parties’ information technology systems and data, including those of cloud providers and third parties with which such other parties conduct business. We rely upon the capacity, reliability and security of our information technology systems, including Internet sites, computer software, data hosting facilities and other hardware and platforms, some of which are hosted by third parties, to assist in conducting our business. Our technologies systems and networks, and those of our business associates, may become the target of cybersecurity attacks, including without limitation malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems and materially and adversely affect us in a variety of ways, including the following:

 

●

unauthorized access to and release of seismic data, reserves information, strategic information or other sensitive or proprietary information, which could have a material adverse effect on our ability to compete for oil and gas resources;

 

●

data corruption, or other operational disruption during drilling or completion activities could result in failure to reach the intended target or a drilling or other operational incident, personal injury, damage to equipment or the subsurface or otherwise adversely affect our operations;

 

●

data corruption or operational disruption of production infrastructure, which could result in loss of production, accidental discharge and other operational incidents;

 

 

●

unauthorized access to and release of personal identifying information of royalty owners, employees and vendors, which could expose us to allegations that we did not sufficiently protect that information;

 

●

a cybersecurity attack on a vendor or service provider, which could result in supply chain disruptions and could delay or halt operations;

 

●

a cybersecurity attack on third-party gathering, transportation, processing, fractionation, refining or export facilities, which could delay or prevent us from transporting and marketing our production, resulting in a loss of revenues;

 

●

a cybersecurity attack on our automated and surveillance systems could cause a loss in production, potential environmental hazards and other operational problems; and

 

●

a corruption or loss of our financial or operating data could result in events of non-compliance which could then lead to regulatory fines or penalties.

 

In addition, certain cybersecurity incidents, such as surveillance, may remain undetected for an extended period. We may be the target of such attacks and, as cybersecurity threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any security vulnerabilities. Additionally, the growth of cybersecurity attacks has resulted in evolving legal and compliance matters which impose significant costs that are likely to increase over time.

 

We cannot assess the extent of either the threat or the potential impact of future terrorist or cybersecurity attacks on the energy industry in general, and on us in particular, either in the short-term or in the long-term. Uncertainty surrounding such attacks may affect our operations in unpredictable ways.

 

Failure to adequately protect critical data and technology systems and the impact of data privacy regulation could materially affect us.

Along with our own data and information in the normal course of business, we collect and retain significant volumes of certain types of data, some of which are subject to specific laws and regulations. The transfer and use of this data both domestically and across international borders is becoming increasingly complex. Information technology solution failures, network disruptions and breaches of data security could disrupt our operations by causing delays or canceling or impeding processing of transactions and reporting financial results, resulting in the unintentional disclosure of employee, royalty owner, or other third party or our information, or damage to our reputation. There can be no assurance that a system failure or data security breach will not have a material adverse effect on our operations, financial condition, results of operations or cash flows.

 

In addition, new laws and regulations governing data privacy at the federal, state, international, national, provincial and local levels, including recent Colorado legislation, the European Union General Data Protection Regulation (“GDPR”) and the California Consumer Privacy Act (“CCPA”), and the unauthorized disclosure of confidential information, pose increasingly complex compliance challenges and potentially elevate costs, and any failure to comply with these laws and regulations could result in significant penalties and legal liability. For example, the GDPR applies to activities regarding personal data that may be conducted by us, directly or indirectly through vendors and subcontractors, from an establishment in the European Union. Failure to comply could result in significant penalties of up to a maximum of 4.0% of our global turnover that may materially adversely affect our business, reputation, results of operations, and cash flows. Similarly, the CCPA, which came into effect on January 1, 2020, gives California residents specific rights in relation to their personal information, requires that companies take certain actions, including notifications for security incidents and may apply to activities regarding personal information that is collected by us, directly or indirectly, from California residents. As interpretation and enforcement of the CCPA evolves, it creates a range of new compliance obligations, which could cause us to change our business practices, with the costs and complexity of compliance, and possibility for significant financial penalties for noncompliance that may materially adversely affect our business, reputation, results of operations, and cash flows.

 

Increased costs of capital could materially adversely affect our business.

 

Our business, ability to make acquisitions and operating results could be harmed by factors such as the availability, terms and cost of capital or increases in interest rates. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, and place us at a competitive disadvantage. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

 

Provisions of our charter documents and Delaware law may inhibit a takeover, which could limit the price investors might be willing to pay in the future for our common stock.

 

Provisions in our certificate of incorporation and bylaws may have the effect of delaying or preventing an acquisition of us or a merger in which we are not the surviving company and may otherwise prevent or slow changes in our board of directors and management. In addition, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the Delaware General Corporation Law. These provisions could discourage an acquisition of us or other change in control transactions and thereby negatively affect the price that investors might be willing to pay in the future for our common stock.

 

 

Risks Related to Regulatory Requirements

 

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. For example, in California, there have been proposals at the legislative and executive levels in the past for tax increases which have included a severance tax as high as 12.5% on all oil production in California. Although the proposals have not passed the California legislature, the State of California could impose a severance tax on oil in the future. Carbon California has significant oil production in California and while we cannot predict the impact of such a tax without having more specifics, the imposition of such a tax could have severe negative impacts on both Carbon California’s willingness and ability to incur capital expenditures in California to increase production, could severely reduce or completely eliminate its California profit margins and would result in lower oil production in its California properties due to the need to shut-in wells and facilities made uneconomic either immediately or at an earlier time than would have previously been the case.

 

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 us, 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 (“BLM”), acting under its authority pursuant to the Mineral Leasing Act of 1920, finalized new regulations in November 2016 that aimed to reduce waste of natural gas from federal and tribal leasehold by imposing new venting, flaring, and leak detection and repair requirements. In December 2017, BLM issued a final rule suspending implementation of the November 2016 rule until January 2019. In February 2018, the suspension was overturned by the U.S. District Court for Northern California. Implementation of these regulations remains uncertain due to ongoing litigation. If these regulations, or other potential regulations, particularly at the local level, are implemented, they 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, which have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. We are often required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that a proposed project may have on the environment, threatened and endangered species, and cultural and archaeological artifacts. The public may comment on and otherwise engage in the permitting process, including through judicial intervention. As a result, the permits we need may not be issued, or if issued, may not be issued in a timely manner or may impose requirements that restrict our ability to conduct operations.

 

 

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

 

New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we are not able to recover the resulting costs through 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.

 

In response to findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment, the EPA has issued regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. These regulations include limits on tailpipe emissions from motor vehicles and preconstruction and operating permit requirements for certain large stationary sources. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis. In December 2015, the EPA finalized rules that added new sources to the scope of the greenhouse gases monitoring and reporting rule. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities. In June 2016, the EPA finalized rules that establish new air emission controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. However, the EPA has taken several steps to delay implementation of the agency’s methane standards, and proposed rulemaking in August 2019 to remove sources in the transmission and storage segment from the regulated source category and rescind the methane-specific requirements from the production and processing segments. The EPA has not yet published a final rule but, as a result of these developments, future implementation of the 2016 rules is uncertain at this time. In addition, various industry and environmental groups have separately challenged both the original methane requirements and the EPA’s attempts to delay implementation of the rules. As a result, substantial uncertainty exists with respect to future implementation of the EPA’s methane rules. Compliance with rules to control methane emissions require enhanced record-keeping practices, the purchase of new equipment such as optical gas imaging instruments to detect leaks and the increased frequency of maintenance and repair activities to address emissions leaks. The rules also may require hiring additional personnel to support these activities or the engagement of third-party contractors to assist with and verify compliance with these new and proposed rules and could increase the cost of our operations. These rules, or similar proposed rules could result in increased compliance costs for us.

 

In addition, Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and many states have already established greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. Internationally, the United Nations Framework Convention on Climate Change finalized an agreement among 195 nations at the 21st Conference of the Parties in Paris with an overarching goal of preventing global temperatures from rising more than 2 degrees Celsius. The agreement includes provisions that every country take some action to lower emissions, but there is no legal requirement for how or by what amount emissions should be lowered.

 

 

California has been one of the leading states in adopting greenhouse gas emission reduction requirements and has implemented a cap and trade program as well as mandates for renewable fuels sources. California’s cap and trade program requires Carbon California to report its greenhouse gas emissions and essentially sets maximum limits or caps on total emissions of greenhouse gases from all industrial sectors that are or become subject to the program. This includes the oil and natural gas extraction sector of which Carbon California is a part. Carbon California’s main sources of greenhouse gas emissions for its Southern California oil and gas operations are primarily attributable to emissions from internal combustion engines powering generators to produce electricity, flares for the disposal of excess field gas, and fugitive emission from equipment such as tanks and components. Under the California program, the cap declines annually from 2013 through 2020. In July 2017, California extended the cap and trade program to 2030. Under the cap and trade program, Carbon California is required to obtain authorizations for each metric ton of greenhouse gases that it emits, either in the form of allowances (each the equivalent of one ton of carbon dioxide) or qualifying offset credits. A portion of the allowance will be granted by the state, but any shortfall between the state-granted allowance and the facility’s emissions will have to be addressed through the purchase of additional allowances either from the state or a third party. The availability of allowances will decline over time in accordance with the declining cap, and the cost to acquire such allowances may increase over time. However, we do not expect the cost to be material to Carbon California’s operations.

 

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements, or they could promote the use of alternative fuels and thereby decrease demand for the oil and gas that we produce. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produced. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. In addition to the regulatory efforts described above, there have also been efforts in recent years in the investment community promoting the divestment of fossil fuel equities as well as to pressure lenders and other financial services companies to limit or curtail activities with companies engaged in the extraction of fossil fuel reserves. Members of the investment community have recently increased their focus on sustainability practices, including practices related to GHGs and climate change, in the oil and natural gas industry. As a result of these efforts, our ability to access capital markets may be limited and our stock price may be negatively impacted. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. Our hydraulic fracturing operations require large amounts of water. Such climatic events could have an adverse effect on our financial condition and results of operations.

 

Environmental legislation and regulatory initiatives, including those relating to hydraulic fracturing and underground injection, 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 our reserves in the Appalachia Basin 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. 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.

 

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 asserted federal regulatory authority pursuant to the federal SDWA over hydraulic fracturing involving fluids that contain diesel fuel and published permitting guidance in February 2014 for hydraulic fracturing operations that use diesel fuel in fracturing fluids in those states in which EPA is the permitting authority. In recent years, the EPA has issued final regulations under the federal CAA establishing performance standards for completions of hydraulically fractured oil and natural gas wells, compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. EPA also finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Federal agencies have also proposed requirements for hydraulic fracturing activities on federal lands and many producing states, cities and counties have adopted, or are considering adopting, regulations that impose more stringent permitting, public disclosure and well construction requirements on hydraulic fracturing operations or bans or moratoria on drilling that effectively prohibit further production of oil and natural gas through the use of hydraulic fracturing or similar operations. For example, several jurisdictions in California have proposed various forms of moratoria or bans on hydraulic fracturing and other hydrocarbon recovery techniques, including traditional waterflooding, acid treatments and cyclic steam injection.

 

 

Moreover, while the scientific community and regulatory agencies at all levels are continuing to study a possible linkage between oil and gas activity and induced seismicity, some state regulatory agencies have modified their regulations or guidance to regulate potential causes of induced seismicity including fluid injection or oil and natural gas extraction. In addition, the DOGGR, renamed the Geologic Energy Management Division, or CalGEM, effective January 1, 2020, adopted regulations intended to bring California’s Class II Underground Injection Control (UIC) program into compliance with the federal Safe Drinking Water Act, under which some wells may require an aquifer exemption. DOGGR reviewed all active UIC projects, regardless of whether an exemption is required. DOGGR has obtained aquifer exemptions for UIC wells identified as requiring an aquifer exemption. In addition, DOGGR, now CalGEM, has undertaken a comprehensive examination of existing regulations and is in the process of issuing additional regulations with respect to certain oil and gas activities, such as management of idle wells, pipelines, underground fluid injection and well construction. CalGEM announced in November 2019 that these rule updates would include public health and safety protections for communities near oil and gas production and independent reviews of permitting processes for hydraulic fracturing and other well stimulation practices. If new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase and our ability to continue production may be delayed or limited, which could have an adverse effect on our results of operation and financial position.

 

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 or underground injection.

 

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

 

FERC has civil penalty authority under the Natural Gas Act (“NGA”), the Natural Gas Policy Act, and the rules, regulations, restrictions, conditions and orders promulgated under those statutes, including regulations prohibiting market manipulation in connection with the purchase or sale of natural gas, to impose penalties for current violations of up to approximately $1.3 million per day for each violation and disgorgement of profits associated with any violation. This maximum penalty authority established by statute will continue to be adjusted periodically for inflation.

 

Section 1(b) of the NGA exempts certain natural gas gathering facilities from regulation by FERC. We believe that our natural gas gathering pipelines meet the traditional tests FERC has used to establish a pipeline’s status as an exempt gatherer not subject to regulation as a natural gas company. While our systems have not been regulated by FERC as a natural gas company under the NGA, we are required to report aggregate volumes of natural gas purchased or sold at wholesale to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. In addition, Congress may enact legislation, FERC may adopt regulations, or a court may make a determination that may subject certain of our otherwise non-FERC jurisdictional facilities to further regulation. Failure to comply with those regulations in the future could subject us to civil penalty liability.

 

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 several 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 2016, the CFTC proposed rules on capital requirements that may have an impact on our hedging counterparties, as the proposed rules would require certain swap dealers and major swap participants to calculate capital requirements inclusive of swaps with commercial end-users. The CFTC has not yet acted on this proposed rulemaking. Also, in December 2016, the CFTC re-proposed regulations regarding position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents, subject to exceptions for certain bona fide hedging transactions. The CFTC has not acted on the re-proposed position limit regulations. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time. However, as proposed, Carbon anticipates that its swaps would qualify as exempt bona fide hedging transactions. 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.

 

 

Risks Related to 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.

 

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common stock.

 

We are required to disclose material changes made in our internal control over financial reporting on a quarterly basis and we are required to assess the effectiveness of our controls annually. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. We cannot be certain that our efforts to maintain our internal controls will be successful or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. We may incur significant costs in our efforts to comply with Section 404. As a smaller reporting company, we are exempt from the requirement to obtain an external audit on the effectiveness of internal controls over financial reporting provided in Section 404(b) of the Sarbanes-Oxley Act. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common stock.

 

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 currently 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 Over-The-Counter Electronic Bulletin Board (“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. As of March 16, 2020, the closing price for our common stock on the OTCQB was $4.30 per share and therefore is considered 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.

 

 

We are a “smaller reporting company” and the reduced disclosure requirements applicable to smaller reporting companies may make our common stock less attractive to investors.

 

We are considered a “smaller reporting company” (a company that has a public float of less than $250 million). We are therefore entitled to rely on certain reduced disclosure requirements, such as an exemption from providing selected financial data and executive compensation information. These exemptions and reduced disclosures in our SEC filings due to our status as a smaller reporting company mean our auditors do not review our internal control over financial reporting and may make it harder for investors to analyze our results of operations and financial prospects. We cannot predict if investors will find our common stock less attractive because we may rely on these exemptions. 

 

Increasing attention to environmental, social and governance matters may impact our business, financial results or stock price.

 

In recent years, increasing attention has been given to corporate activities related to environmental, social and governance (“ESG”) matters in public discourse and the investment community. A number of advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote change at public companies related to ESG matters, including through the investment and voting practices of investment advisers, public pension funds, universities and other members of the investing community. These activities include increasing attention and demands for action related to climate change, promoting the use of substitutes to fossil fuel products, and encouraging the divestment of companies in the fossil fuel industry. These activities could reduce demand for our products, reduce our profits, increase the potential for investigations and litigation, impair our brand and have negative impacts on the price of our common stock and access to capital markets.

 

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings systems for evaluating companies on their approach to ESG matters. These ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital.

 

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

 

Currently, our key stockholders 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.

 

Terms of subsequent financings may adversely impact stockholder equity.

 

We may raise additional capital through the issuance of equity or debt in the future. In that event, the ownership of our existing stockholders would be diluted, and the value of the stockholders’ equity in common stock could be reduced. If we raise more equity capital from the sale of common stock, institutional or other investors may negotiate terms more favorable than the current prices of our 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 stockholders 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.

 

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

 

Item 1B. Unresolved Staff Comments.

 

None.

 

Item 3. Legal Proceedings. 

 

We are subject to legal claims and proceedings in the ordinary course of our business. Management believes that should the controversies be resolved against us, none of the current pending proceedings would have a material adverse effect on us.

 

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.

 

Market Information

 

Carbon has one class of common shares outstanding, which has a par value of $0.01 per share. Our common stock is quoted on the OTCQB under the symbol CRBO.

 

The limited and sporadic quotations of our common stock does not constitute an established trading market for our common stock. There can be no assurance that an active market will develop for our common stock in the future.

 

The following table sets forth the high and low bid price per share of our common stock for each quarter for the years ended December 31, 2019 and 2018, as quoted on the OTCQB. The information reflects inter-dealer prices, without retail mark-up, mark-down or commissions and may not represent actual transactions:

 

Year Ended December 31,		Quarter		High				Low
2019		First		$	10.00			$	9.25
		Second		$	10.00			$	5.00
		Third		$	8.00			$	4.00
		Fourth		$	4.00			$	3.15
2018		First		$	11.00			$	9.80
		Second		$	12.00			$	9.80
		Third		$	13.00			$	9.50
		Fourth		$	9.25			$	6.50

 

As of March 16, 2020, the closing price for our common stock on the OTCQB was $4.30 per share. 

 

Holders

 

As of March 16, 2020, there were approximately 349 holders of record of our common stock. The number of holders does not include the stockholders for whom shares are held in a “nominee” or “street” name.

 

Dividends

 

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 revenue and earnings, capital requirements, if any, and general financial condition, and will be within the discretion of our Board of Directors. We have historically retained our future earnings to support operations and to finance our business.

 

Our ability to pay dividends is currently limited by:

 

	●	the terms of our credit facility that prohibit us from paying dividends on our common stock while amounts are owed under our credit facility;
	●	the terms of the Carbon California Senior Secured Notes and the Subordinated Notes, which prevent Carbon California from paying dividends to us; and
	●	the Delaware General Corporation Law, which provides that a Delaware corporation may pay dividends either out of the corporation’s surplus (as defined by Delaware law) or 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 to pay dividends will depend on our financial condition, capital requirements, results of operations, contractual limitations, legal restrictions, our required payments of principal associated with the term loan under our credit facility and any other factors the Board of Directors deems relevant.

 

 

Securities Authorized for Issuance Under Equity Compensation Plans

 

The information relating to our equity compensation plans required by Item 5 is incorporated by reference to such information as set forth in Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters of this report.

 

Recent Sales of Unregistered Securities; Use of Proceeds from Registered Securities

 

None

 

Item 6. Selected Financial Data.

 

As a smaller reporting company, we are not required to provide information for this item.

 

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 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 may 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.” The following discussion should be read in conjunction with “Forward-Looking Statements,” “Risk Factors” and our consolidated financial statements, including the notes thereto appearing elsewhere in this Annual Report on Form 10-K.

 

Overview

 

Carbon is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of oil, natural gas and natural gas liquids properties located in the United States. We currently develop and operate oil and gas properties in the Appalachian Basin in Kentucky, Ohio, Tennessee, Virginia and West Virginia, in the Illinois Basin in Illinois and Indiana, and in the Ventura Basin in California through our wholly-owned and majority-owned subsidiaries. We own 100% of the outstanding interests of Nytis USA, which in turn owns 98.11% of Nytis LLC. Nytis LLC holds interests in our operating subsidiaries. We own 53.92% of Carbon California which consolidates as a majority-owned subsidiary. We focus on conventional and unconventional reservoirs, including shale, tight sands and coalbed methane.

 

For a description of our assets, please see Part I, “Business” of this report.

 

At December 31, 2019, our proved developed reserves comprised 18.8% oil, 79.8% natural gas and 1.4% NGL. Our current capital expenditure program is focused on the acquisition and development of oil and natural gas properties in areas where we currently operate. We believe that our asset and lease position, combined with our low operating expense structure and technical expertise, 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:

 

	●	acquire and develop oil and gas producing properties that provide attractive risk adjusted rates of return, field development projects and complement our existing asset base; and
	●	develop, optimize and maintain a portfolio of low risk, long-lived oil and natural gas properties that provide stable cash flows and attractive risk adjusted rates of return.

 

 

Factors That Significantly Affect Our Financial Condition and Results of Operations

 

Our revenue, profitability and future growth rate depend on many factors which are beyond our control, including but not limited to, economic, political and regulatory developments and competition from other industry participants. Our financial results are sensitive to fluctuations in oil and natural gas prices. Oil and gas prices historically have been volatile and may fluctuate widely in the future due to a variety of factors, including but not limited to, prevailing economic conditions, supply and demand of hydrocarbons in the marketplace, actions by speculators, and geopolitical events such as wars or natural disasters. In March 2020, in response to the failure of the Organization of the Petroleum Exporting Countries and the Russian Federation to agree on production quotas, the Kingdom of Saudi Arabia announced its intent to maximize near-term oil production, which, together with the decline in demand due to slowed economic conditions attributable to COVID-19, contributed to a decline in the price of crude oil from $61.14 per barrel on December 31, 2019 to $28.70 per Bbl on March 16, 2020. The following table highlights the quarterly average of NYMEX oil and natural gas prices for the last eight calendar quarters:

 

		2019																2018
		Q1				Q2				Q3				Q4				Q1				Q2				Q3				Q4
Oil (Bbl)		$	54.90			$	59.96			$	56.43			$	56.87			$	62.89			$	67.90			$	69.50			$	58.83
Natural Gas (MMBtu)		$	3.00			$	2.57			$	2.38			$	2.40			$	3.13			$	2.77			$	2.88			$	3.62

  

Low oil and natural gas prices may decrease our revenues, may reduce the amount of oil, natural gas and natural gas liquids that we can produce economically and potentially lower our oil and natural gas reserves. Our estimated proved reserves may decrease if the economic life of the underlying producing wells is 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. 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 lenders and may make it more difficult to comply with the covenants and other restrictions under our bank credit facility.

 

We use the full cost method of accounting for our oil and gas properties and perform a ceiling test quarterly. The ceiling calculation utilizes a rolling 12-month average commodity price. We did not recognize an impairment in 2019 or 2018. 

 

Future write downs or impairments, if any, are difficult to 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. There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in subsequent periods.

 

We use commodity derivative instruments, such as swaps and costless collars, to manage and reduce price volatility and other market risks associated with our production. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases. Please read “Business-Risk Management” for additional discussion of our commodity derivative contracts.

 

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.

 

Future property 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

 

During 2019 and 2018, we concentrated our efforts on the acquisition and development of producing properties through the acquisitions consummated by Carbon California and Carbon Appalachia. On December 31, 2018, we completed the purchase of Old Ironsides’ interests in Carbon Appalachia, resulting in ownership of 100% of Carbon Appalachia. Our field development activities have consisted principally of oil-related drilling, remediation and return to production and recompletion projects in California. Since closing these acquisitions, we have focused on operating efficiencies and reduction of operating expenses, optimization of natural gas gathering and compression facilities, greater flexibility in transporting our production to markets with more favorable pricing, and the identification of development project opportunities to provide more efficient and lower-cost operations. During the second half of 2019, we executed a two-well drilling program in California, and as a result of such drilling program, one well was completed in the fourth quarter of 2019 and the other was completed during the first quarter of 2020. Subject to the recovery of oil pricing in the remainder of 2020, we plan to execute a five-well drilling program in California in 2020.

 

As of December 31, 2019, we owned working interests in approximately 7,200 gross wells (6,600 net), royalty interests located primarily in California, Illinois, Indiana, Kentucky, Ohio, Tennessee, Virginia, and West Virginia and had leasehold positions in approximately 313,900 net developed acres and approximately 1,256,900 net undeveloped acres. Approximately 75.0% of the undeveloped acreage is held by production and of the remaining undeveloped acreage, approximately 88.0% have lease terms of greater than five years remaining in the primary term or contractual extension periods.

 

Our oil and natural gas assets contain an inventory of field development projects which may provide growth opportunities when oil and natural gas commodity prices warrant capital investment to develop the properties.

 

How We Evaluate Our Operations

 

In evaluating our financial results, we focus on the mix of our revenues from oil, natural gas, and NGLs, the average realized price from sales of our production, our production margins, and our capital expenditures.

 

We also evaluate our rates of return on invested capital in our wells. We believe the quality of our assets combined with the technical capabilities of our management team can generate attractive rates of return as we develop our extensive resource base. Additionally, by focusing on concentrated acreage positions, we can utilize centralized production infrastructure, which enable us to reduce reliance on outside service companies, minimize costs, and increase our returns.

 

Principal Components of Our Cost Structure

 

●

Lease operating expenses. Lease operating expenses are costs incurred to bring oil and natural gas out of the ground, 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.

 

●

Pipeline operating expenses. Pipeline operating expenses are costs incurred to accept, transport and deliver gas across our midstream assets.

 

●

Transportation and gathering costs. Transportation and gathering costs are incurred to bring oil and natural gas to market. Gathering refers to the utilization of low-pressure pipelines to move the oil and natural gas from the wellhead into a transportation pipeline, or in case of oil, into a tank battery from which sales of oil are made.

 

●

Production and property taxes.  Production and property taxes consist of severance, property and ad valorem taxes. Production and severance taxes 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. Ad valorem tax rates, which can fluctuate by year, are determined by individual counties where we have production and are assessed on our sales one or two years in arrears depending on the location of the production.

 

●

Marketing gas purchases.  Marketing gas purchases consist of third-party purchases of gas associated with our midstream operations.

 

●

Depreciation, amortization and impairment. We use 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. We perform a quarterly ceiling test based on average first-of-the-month prices during the twelve-month period prior to the reporting date. 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 our full cost pool to estimated discounted cash flows. Should the net capitalized costs exceed the sum of the estimated discounted cash flows, a ceiling test write-down would be recognized to the extent of the excess.

 

 

●

Depletion. 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.  General and administrative expense includes payroll and benefits for our corporate staff, non-cash stock-based compensation, costs of maintaining our offices, costs of managing our production, marketing, development and acquisition operations, franchise taxes, audit, tax, legal and other professional fees and legal compliance. Certain of these costs were recovered as management reimbursements in place with Carbon California and, prior to the completion of the OIE Membership Acquisition on December 31, 2018, Carbon Appalachia.

 

●

Interest expense.  We finance a portion of our working capital requirements for project development activities and acquisitions with borrowings under our bank credit facilities. 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 until 2023 tangible drilling costs 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. See Note 12 – Income Taxes in the consolidated financial statements in Item 8 for more information.

 

Factors Affecting Our Business and Outlook

 

The price we receive for our oil, natural gas and NGL production heavily influences our revenue, profitability, access to capital and future rate of growth. Our revenues, cash flow from operations, and future growth depend substantially on factors beyond our control, such as economic, political, and regulatory developments and competition from other sources of energy. Oil, natural gas and NGLs are commodities, and therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Sustained periods of low prices for oil, natural gas, or NGLs could materially and adversely affect our financial condition, our results of operations, the quantities of oil and natural gas that we can economically produce, and our ability to access capital. See – “Risk Factors - Oil, NGL and natural gas prices and differentials are highly volatile. Declines in commodity prices, especially steep declines in the price of oil, have adversely affected, and in the future will adversely affect, our financial condition and results of operations, cash flow, access to the capital markets and ability to grow.”

 

We use commodity derivative instruments, such as swaps and collars, to manage and reduce price volatility and other market risks associated with our production. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases. We do not apply hedge accounting, and therefore designate our current portfolio of commodity derivative contracts as hedges for accounting purposes and all changes in commodity derivative fair values are immediately recorded to earnings.

 

Like all businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well naturally decreases. Thus, an oil and natural gas exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces. We attempt to overcome this natural decline by acquiring more reserves than we produce, conducting field development projects or drilling to find additional reserves. Our future growth will depend on our ability to continue to acquire reserves in a cost-effective manner and enhance production levels from our existing reserves. Our ability to continue to acquire reserves and to add reserves through drilling is dependent on our capital resources and commodity prices and can be limited by many factors, including our ability to access capital in a cost-effective manner and to timely obtain drilling permits and regulatory approvals.

 

As with our historical acquisitions, any future acquisitions could have a substantial impact on our financial condition and results of operations. In addition, funding future acquisitions may require us to incur additional indebtedness or issue additional equity.

 

Factors Affecting Comparability of Results of Operations

 

Acquisitions affect the comparability of our financial statements from period to period. In December 2018, we completed the OIE Membership Acquisition and as a result, we now hold all of the issued and outstanding ownership interests of Carbon Appalachia, along with its direct and indirect subsidiaries. As a result, we consolidate Carbon Appalachia for financial reporting purposes. As discussed in Note 3 – Acquisitions in the consolidated financial statements in Item 8, we completed several acquisitions during 2018 in addition to the OIE Membership Acquisition; therefore, the financial data for 2018 is not comparable in all respects to the financial data for 2019 and is not necessarily indicative of our future results. 

 

 

Results of Operations

 

The following table sets forth for the periods presented our selected historical statements of operations and production data.

 

		Year Ended
		December 31,								Percent
(in thousands except production and per unit data)		2019				2018(1)				Change
Revenue:
Natural gas sales		$	56,468			$	16,018				253	%
Natural gas liquids sales			578				1,143				(49	)%
Oil sales			36,795				30,891				19	%
Transportation and handling			1,928				-				*
Marketing gas sales			16,920				-				*
Commodity derivative gain			3,044				4,894				*
Other income			892				105				*
Total revenues			116,625				53,051				120	%
Expenses:
Lease operating expenses			29,714				15,960				86	%
Pipeline operating expenses			11,153				-				*
Transportation and gathering costs			6,086				4,453				37	%
Production and property taxes			5,507				1,813				204	%
Marketing gas purchases			18,684				-				*
General and administrative			16,342				13,779				(19	)%
General and administrative–deferred fees write-down			-				1,999				*
General and administrative–related party reimbursement			-				(4,547	)			*
Depreciation, depletion and amortization			15,757				8,108				94	%
Accretion of asset retirement obligations			1,625				868				87	%
Total expenses			104,868				42,433				147	%
Operating income		$	11,757			$	10,618				11	%
Other income and (expense):
Interest expense		$	(12,848	)		$	(5,920	)			117	%
Warrant derivative gain			-				225				*
Gain on derecognized equity investment in affiliate-Carbon California			-				5,390				*
Investment in affiliates			90				2,469				*
Other income			-				(3	)			*
Total other (expense) income		$	(12,758	)		$	2,161				*
Production data:
Natural gas (MMcf)			21,436				5,320				303	%
Oil (MBbl)			589				451				31	%
Natural gas liquids (MBbl)			36				33				8	%
Combined (MMcfe)			25,182				8,223				206	%
Average prices before effects of hedges:
Natural gas (per Mcf)		$	2.63			$	3.01				(13	)%
Oil and liquids (per Bbl)		$	62.50			$	68.53				(9	)%
Natural gas liquids (per Bbl)		$	16.18				34.55				(53	)%
Combined (per Mcfe)		$	3.73			$	5.84				(36	)%
Average prices after effects of hedges**:
Natural gas (per Mcf)		$	2.80			$	2.96				(5	)%
Oil and liquids (per Bbl)		$	62.38			$	60.65				3	%
Natural gas liquids (per Bbl)		$	16.18				34.55				(53	)%
Combined (per Mcfe)		$	3.87			$	5.38				(28	)%
Average costs (per Mcfe):
Lease operating expenses		$	1.18			$	1.94				(39	)%
Transportation costs		$	0.24			$	0.54				(56	)%
Production and property taxes		$	0.22			$	0.22				0	%
Depreciation, depletion and amortization		$	0.63			$	0.99				(36	)%

 

*	Not meaningful or applicable

**

Includes effect of settled commodity derivative gains and losses

(1)

Includes Carbon California activity for the period of consolidation from February 1, 2018 through December 31, 2018, and other than investment in affiliates does not include Carbon Appalachia activity during 2018 as Carbon Appalachia did not consolidate until December 31, 2018 upon the closing of the OIE Membership Acquisition. As of December 31, 2019, Carbon owned 100% of Carbon Appalachia and holds a 53.92% proportionate share of Carbon California. See Factors Affecting Comparability of Results of Operations.

 

 

2019 Compared to 2018

 

Oil and natural gas sales- Sales of natural gas, natural gas liquids and oil increased by approximately $46.0 million during 2019 as compared to 2018 primarily due to a 206% increase in natural gas, natural gas liquids and oil sales volumes, partially offset by a 36% decrease in combined product pricing. The increases in production were primarily due to the acquisitions of Carbon Appalachia and Carbon California and the resultant consolidation of the related activity for the year ended December 31, 2019.

 

Commodity derivative gains (losses)- To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we enter into derivative contracts using fixed price swap contracts and costless collars. 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 settlement gains or losses on the derivative instruments, are currently recognized in our results of operations. The unrealized gains and losses represent the changes in the fair value of these contracts as oil and natural gas futures prices fluctuate relative to the fixed price we will receive from these contracts. For the years ended December 31, 2019 and 2018, we had commodity derivative gains of approximately $3.0 million and $4.9 million, respectively.

 

Lease operating expenses- Lease operating expenses increased approximately $14.0 million during 2019 as compared to 2018, primarily due to the OIE Membership Acquisition and the resultant increased production volumes. Lease operating expenses associated with oil production are generally higher on a per Mcfe basis versus gas production.

 

Transportation and gathering costs- Transportation and gathering costs increased by 37% during 2019, as compared to 2018 primarily due to the OIE Membership Acquisition and a full year of Carbon California operations.

 

Production and property taxes- Production and property taxes increased 204% during 2019 as compared to 2018 due to increased oil and natural gas sales as a result of the consolidation of Carbon Appalachia and a full year of Carbon California production, partially offset by decreased ad valorem estimated tax rates. Production taxes averaged approximately 4% and 2% of product sales for the years ended December 31, 2019 and 2018, respectively. Production taxes associated with oil production are generally lower on a per Mcfe basis versus gas production. Oil production accounted for approximately 14% and 33% of our production mix for the years ended December 31, 2019 and 2018, respectively.

 

Depreciation, depletion and amortization (DD&A)- DD&A increased approximately $8.0 million during 2019 as compared to 2018, primarily due to increased oil and natural gas production and the increase in oil and gas properties associated with the OIE Membership Acquisition.

 

General and administrative expenses- General and administrative expenses decreased by 4% during 2019 as compared to 2018, primarily due to $2.0 million in financing costs written off during 2018 for an abandoned equity offering. Such financing costs were not incurred during 2019. As a result of the consolidation of Carbon Appalachia and Carbon California, management reimbursements which partially offset general and administrative expenses are now eliminated. These management reimbursements account for a decrease of approximately $4.6 million during 2019 as compared to 2018. On a per Mcfe basis, cash-based general and administrative expenses, net of related party reimbursements, decreased from $1.23 per Mcfe for 2018 to $0.59 per Mcfe for 2019. Cash-based general and administrative expenses for the years ended December 31, 2019 and 2018 are summarized in the following table:

 

General and administrative expenses		Year Ended December 31,
(in thousands)		2019				2018
General and administrative expenses		$	16,342			$	15,778
Adjustments:
Stock-based compensation			(1,448	)			(1,133	)
General and administrative – related party reimbursement			-				(4,547	)
Cash-based general and administrative expense		$	14,894			$	10,098

 

 

Interest expense- Interest expense increased by 117% during 2019 as compared to 2018, primarily due to higher outstanding debt balances related to borrowings to complete the OIE Membership Acquisition.

 

Transportation and handling, marketing gas sales, pipeline operating expenses and marketing gas purchases– Subsequent to the OIE Membership Acquisition on December 31, 2018, we consolidate Carbon Appalachia operations. The associated revenues and expenses are presented within our consolidated statements of operations during the year ended December 31, 2019. These revenues and expenses were not presented in our consolidated statements of operations during the year ended December 31, 2018.

 

Liquidity and Capital Resources

 

Our primary sources of liquidity and capital resources are cash flows from operations, borrowings under our credit facility and Carbon California Senior Revolving Notes, and the sale of non-core assets. Borrowings under the credit facility and Carbon California Senior Revolving Notes may be used to fund field development projects, to fund future complementary acquisitions and for general working capital purposes. We may use other sources of capital, including the issuance of debt or equity securities, to fund acquisitions or maintain financial flexibility.

 

As of December 31, 2019, our liquidity was approximately $17.9 million, consisting of cash on hand of approximately $900,000 and approximately $17.0 million of available borrowing capacity on our credit facility and Carbon California Senior Revolving Notes. On February 14, 2020, we amended our credit facility, resulting in a borrowing base of $73.0 million with subsequent borrowing base reductions totaling $6.0 million scheduled through May 1, 2020.

 

On December 31, 2018, we closed the OIE Membership Acquisition. As a result, we now own 100% of all interests in Carbon Appalachia; therefore, we receive 100% of the cash flows associated with Carbon Appalachia.

 

Prior to the consolidation of Carbon California and Carbon Appalachia effective February 1, 2018 and December 31, 2018, respectively, we generated operating cash flow by providing management services to these unconsolidated subsidiaries. These management service reimbursements were included in general and administrative – related party reimbursement on our consolidated statement of operations. We also received reimbursements of operating expenses, our share of which were included in investments in affiliates on our consolidated statement of operations. As we now consolidate Carbon California and Carbon Appalachia, these management and operating reimbursements are eliminated in the consolidated statement of operations for the year ended December 31, 2019.

 

We continuously evaluate our portfolio of oil and gas assets and make acquisitions, investments and divestitures as part of our strategic plan. In the current environment, we are actively analyzing options such as selling assets, including potentially our Appalachian business, primarily in order to reduce indebtedness and, to a lesser extent, to fund higher value acquisition or development opportunities. Any decision to divest would be made based upon several criteria, including but not limited to the value we could obtain for such assets, the outlook for commodity prices, our expected return on invested capital and the impact on our overall leverage.

 

Commodity Derivatives

 

Our exploration, development and acquisition activities may require us to make significant operating and capital expenditures. 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.

 

This hedge program mitigates uncertainty regarding cash flow that we will receive with respect to a portion of our expected production through 2022. 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. See Note 14 – Commodity Derivatives in the consolidated financial statements in Item 8 for more information, including further details about our outstanding derivatives.

 

Credit Facilities and Notes Payable

 

We have a $500.0 million bank credit facility with Prosperity Bank (formerly known as LegacyTexas Bank), as the administrative agent, and a syndicate of financial institutions, as lenders. The credit facility has a borrowing base of $75.0 million at December 31, 2019 and $72.0 million at March 16, 2020, the outstanding balance of which was approximately $69.2 million at December 31, 2019 and $71.2 million at March 16, 2020. Additionally, we have $15.0 million associated with a term loan under the same facility, which balance was approximately $5.8 million at December 31, 2019 and $3.3 million at March 16, 2020. Finally, we have notes payable to Old Ironsides, the balance of which was approximately $25.7 million as of December 31, 2019 and March 16, 2020.

 

For further information about our outstanding debt, see Note 7 – Credit Facilities and Notes Payable in the consolidated financial statements in Item 8.

 

 

Sources and Uses of Cash

 

The following table presents net cash provided by or used in operating, investing and financing activities:

 

		Year Ended
		December 31,
(in thousands)		2019				2018
Net cash provided by operating activities		$	18,856			$	10,845
Net cash used in investing activities		$	(6,570	)		$	(70,436	)
Net cash (used in) provided by financing activities		$	(17,118	)		$	63,677

 

Operating Activities

 

Net cash provided by operating activities is primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and changes in working capital. Operating cash flows increased approximately $8.0 million for the year ended December 31, 2019 as compared to the same period in 2018. This increase was primarily due to increased revenues attributable to the OIE Membership Acquisition and Seneca Acquisition.

 

Investing Activities

 

Net cash used in investing activities is primarily comprised of the acquisition, exploration and development of oil and natural gas properties in addition to expenditures to fund our drilling program in Carbon California, net of dispositions of oil and natural gas properties. Net cash used in investing activities decreased approximately $63.9 million for the year ended December 31, 2019 as compared to the same period in 2018, primarily due to the OIE Membership Acquisition and Seneca Acquisition consummated in 2018.

 

Financing Activities

 

Net cash provided by or used in financing activities is primarily comprised of activities associated with our credit facility and the Carbon California Senior Revolving Notes. During the year ended December 31, 2019, the Company paid $2.0 million in principal associated with the Old Ironsides Notes, paid approximately $14.2 million in principal associated with our credit facility, and paid approximately $7.5 million in principal associated with the Carbon California Senior Revolving Notes. The payments were partially offset by borrowings under our credit facility and Senior Revolving Notes of approximately $7.0 million.

 

During the year ended December 31, 2018, the Company borrowed approximately $28.0 million to partially fund the Seneca Acquisition in May 2018, borrowed approximately $3.0 million to partially fund the Liberty Acquisition (as defined in Note 3 to the consolidated financial statements in Item 8) in July 2018, and borrowed approximately $84.2 million, netted against approximately $64.2 million in repayments of the previous credit facility, to partially fund the OIE Membership Acquisition in December 2018. Also in 2018, the Company received $5.0 million in proceeds from the issuance of preferred stock to Yorktown and received an equity contribution of $5.0 million from Prudential related to the Seneca Acquisition. 

 

Capital Expenditures

 

Capital expenditures in the table below represent cash used for capital expenditures:

 

		Year Ended December 31,
(in thousands)		2019				2018
Acquisition of oil and gas properties:
Unevaluated properties		$	-			$	3,464
Oil and natural gas producing properties			-				63,517
Drilling and development			7,676				2,074
Pipeline and gathering			-				460
Other			352				921
Total capital expenditures		$	8,028			$	70,436

 

 

During the second half of 2019, we executed a two-well drilling program in California, and as a result of such drilling program, one well was completed in the fourth quarter of 2019 and the other was completed during the first quarter of 2020. Due to low natural gas prices, the Company has focused its Appalachia operations on the optimization of our gathering, compression and storage facilities and marketing arrangements to provide greater flexibility in moving natural gas production to markets with more favorable pricing. Other factors impacting the level of our capital expenditures include the cost and availability of oil field services, general economic and market conditions and weather disruptions. Due to the recent developments surrounding the COVID-19 virus and relative pricing volatility, we are currently evaluating our 2020 capital program.

 

Off-balance Sheet Arrangements

 

We did not have any off-balance sheet arrangements as of December 31, 2019.

 

Critical Accounting Policies, Estimates, Judgments, and Assumptions

 

We prepare our financial statements and the accompanying notes in conformity with GAAP, which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompany notes. We identify certain accounting policies as critical based on, among other things, their impact on the portrayal of our 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 our most critical accounting policies that require management to make difficult, subjective or complex accounting estimates.

 

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. We use the full cost method of accounting as defined by SEC Release No. 33-8995 and FASB ASC 932 because we believe it appropriately reports the costs of our exploration programs as part of an overall investment in discovering and developing proved reserves.

 

Under the full cost method, separate cost centers are maintained for each geographic area 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, 2019 and 2018 reserve estimates were used for our respective period depletion calculations. These reserve estimates were calculated in accordance with SEC rules. See “Business-Reserves” and Notes 2 and 17 to the consolidated financial statements for a more complete discussion of the rule and our estimated proved reserves as of December 31, 2019 and 2018.

 

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 2019 and 2018, we did not recognize a ceiling test impairment. Lower oil and natural gas prices may not only decrease our revenues but may also reduce the amount of oil and natural gas that we 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 on the present value of estimated future net revenues which may require us to recognize impairments of our oil and natural gas properties in future periods.

 

 

In 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. 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 practical 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.

 

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 “Business-Reserves” and “Risk Factors-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 proved reserves.”

 

Accounting for Derivative Instruments

 

We recognize all derivative instruments as either assets or liabilities at fair value. 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.

 

The fair value of our commodity derivative assets and liabilities are measured utilizing a third-party valuation specialist. The valuations consider 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. We review these valuations and analyze changes in the fair value of the derivatives. Volatility in oil and natural gas prices could have a significant impact on the fair value of our derivative contracts. The values we report in our consolidated 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, 2019 and will depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts.

 

 

Income Taxes

 

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 2017, 2018 and 2019, and forecasted book income if commodity prices increase. Negative evidence considered by management includes book losses in certain years 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, 2019 and 2018, management assessed the available positive and negative evidence to estimate if sufficient future taxable income would be generated to use our 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, we recorded a net valuation allowance of approximately $13.1 million and $14.6 million on our deferred tax assets as of December 31, 2019 and 2018, 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. See Note 6 – Asset Retirement Obligations in the consolidated financial statements in Item 8 for more information.

 

Accounting for Business Combinations

 

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. We may use the cost, income, or market valuation approaches depending on the quality of the information available to support management’s assumptions. There is no assurance the underlying assumptions or estimates associated with the valuation will occur as initially expected.

 

Revenue Recognition

 

We derive our revenue from the sale of oil, natural gas and NGLs. Revenues are recognized when we meet our performance obligations to deliver the production volumes and control is transferred. Oil, natural gas and NGL revenues are recognized on the basis of our net working revenue interest. Payment is received 30 to 90 days after the date of production. At the end of each month, we make estimates of the amount of production delivered and the price we will receive. Variances between our estimated revenue and actual amounts received are recorded in the month payment is received.

 

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

 

As a smaller reporting company, we are not required to provide information for this item.

 

 

Item 8. Financial Statements and Supplementary Data.

 

Report of Independent Public Accounting Firm

 

To the Stockholders and Board of Directors

Carbon Energy Corporation

 

Opinion on the Financial Statements

 

We have audited the accompanying consolidated balance sheet of Carbon Energy Corporation (the “Company”) as of December 31, 2019 and 2018, the related consolidated statements of operations, stockholders' equity, and cash flows for the years ended December 31, 2019 and 2018, and the related notes (collectively, referred to as the “financial statements”).

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018 and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

 

Basis for Opinion

 

The Company's management is responsible for these financial statements. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

 

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting 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.

 

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinions.

 

/s/ Plante & Moran, PLLC

 

We have served as the Company’s auditor since 2005.

 

Denver, Colorado

March 30, 2020

 

  

CARBON ENERGY CORPORATION

Consolidated Balance Sheets

(In thousands, except share amounts)

 

		December 31,
		2019				2018
ASSETS
Current assets:
Cash and cash equivalents		$	904			$	5,736
Accounts receivable:
Revenue			12,886				20,223
Joint interest billings and other			1,552				1,218
Insurance receivable (Note 2)			-				522
Commodity derivative asset (Note 14)			5,915				3,517
Prepaid expenses, deposits, and other current assets			2,500				1,645
Inventory			2,512				1,149
Total current assets			26,269				34,010
Non-current assets:
Property and equipment (Note 4)
Oil and gas properties, full cost method of accounting:
Proved, net			242,144				248,455
Unproved			4,872				5,416
Other property and equipment, net			15,984				17,563
Total property and equipment, net			263,000				271,434
Investments in affiliates			625				598
Commodity derivative asset – non-current (Note 14)			1,164				3,505
Right-of-use assets (Note 8)			6,104				-
Other non-current assets			1,092				1,344
Total non-current assets			271,985				276,881
Total assets		$	298,254			$	310,891
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities (Note 5)		$	35,157			$	34,816
Firm transportation contract obligations (Note 15)			5,679				6,129
Lease liability – current (Note 8)			1,625				-
Commodity derivative liability (Note 14)			469				-
Credit facilities and notes payable (Note 7)			5,788				11,910
Total current liabilities			48,718				52,855
Non-current liabilities:
Firm transportation contract obligations (Note 15)			8,905				12,729
Lease liability – non-current (Note 8)			4,383				-
Commodity derivative liability – non-current (Note 14)			87				-
Production and property taxes payable			2,815				2,914
Asset retirement obligations (Note 6)			17,514				19,211
Credit facilities and notes payable (Note 7)			94,870				97,228
Notes payable – related party (Note 7)			44,741				49,919
Total non-current liabilities			173,315				182,001
Commitments and contingencies (Note 15)
Stockholders’ equity:
Preferred stock, $0.01 par value; liquidation preference of $524 and $224 at December 31, 2019 and 2018, respectively; authorized 1,000,000 shares, 50,000 shares issued and outstanding at December 31, 2019 and 2018			1				1
Common stock, $0.01 par value; authorized 35,000,000 shares, 7,796,085 and 7,655,759 shares issued and outstanding at December 31, 2019 and 2018, respectively			78				77
Additional paid-in capital			85,834				84,612
Accumulated deficit			(35,842	)			(36,939	)
Total Carbon stockholders’ equity			50,071				47,751
Non-controlling interests			26,150				28,284
Total stockholders’ equity			76,221				76,035
Total liabilities and stockholders’ equity		$	298,254			$	310,891

  

See accompanying Notes to Consolidated Financial Statements.

 

  

CARBON ENERGY CORPORATION

Consolidated Statements of Operations

(In thousands, except per share amounts)

 

		Year Ended December 31,
		2019				2018
Revenue:
Natural gas sales			56,468				16,018
Natural gas liquids sales			578				1,143
Oil sales			36,795				30,891
Transportation and handling			1,928				-
Marketing gas sales			16,920				-
Commodity derivative gain			3,044				4,894
Other income			892				105
Total revenue			116,625				53,051
Expenses:
Lease operating expenses			29,714				15,960
Pipeline operating expenses			11,153				-
Transportation and gathering costs			6,086				4,453
Production and property taxes			5,507				1,813
Marketing gas purchases			18,684				-
General and administrative			16,342				13,779
General and administrative – deferred fees write-down			-				1,999
General and administrative – related party reimbursement			-				(4,547	)
Depreciation, depletion, and amortization			15,757				8,108
Accretion of asset retirement obligations			1,625				868
Total expenses			104,868				42,433
Operating income			11,757				10,618
Other income and (expense):
Interest expense			(12,848	)			(5,920	)
Warrant derivative gain			-				225
Gain on derecognized equity investment in affiliate-Carbon California			-				5,390
Investments in affiliates			90				2,469
Other			-				(3	)
Total other (expense) income			(12,758	)			2,161
(Loss) income before income taxes			(1,001	)			12,779
Provision for income taxes			-				-
Net (loss) income before non-controlling interests and preferred shares			(1,001	)			12,779
Net (loss) income attributable to non-controlling interests			(2,098	)			4,375
Net income attributable to controlling interests before preferred shares			1,097				8,404
Net income attributable to preferred shares – beneficial conversion feature			-				1,125
Net income attributable to preferred shares – preferred return			300				224
Net income attributable to common shares		$	797			$	7,055
Net income per common share:
Basic		$	0.10			$	0.94
Diluted		$	0.10			$	0.87
Weighted average common shares outstanding:
Basic			7,794				7,525
Diluted			8,095				7,839

 

See accompanying Notes to Consolidated Financial Statements.

 

  

CARBON ENERGY CORPORATION

Consolidated Statements of Stockholders’ Equity

(In thousands)

 

		Common Stock								Preferred Stock								Additional Paid-In				Non- controlling				Accumulated				Total Stockholders’
		Shares				Amount				Shares				Amount				Capital				Interests				Deficit				Equity
Balance as of December 31, 2017			6,006			$	60				-				-			$	58,813			$	1,841			$	(44,218	)		$	16,496
Stock based compensation			-				-				-				-				1,133				-				-				1,133
Vested restricted stock			60				1				-				-				(1	)			-				-				-
Vested performance units			108				1				-				-				(1	)			-				-				-
Restricted stock and performance units exchanged for tax withholding			(46	)			-				-				-				(197	)			-				-				(197	)
Preferred share issuance			-				-				50				1				4,999				-				-				5,000
Beneficial conversion feature			-				-				-				-				1,125				-				(1,125	)			-
California Warrant exercise - share issuance			1,528				15				-				-				8,312				16,465				-				24,792
Majority control of Carbon California (Note 4)			-				-				-				-				10,429				-				-				10,429
Units issued with 2018 Subordinated Notes, related party (Note 7)			-				-				-				-				-				489								489
Non-controlling interest contributions, net			-				-				-				-				-				5,114				-				5,114
Net income			-				-				-				-				-				4,375				8,404				12,779
Balance as of December 31, 2018			7,656			$	77				50			$	1			$	84,612			$	28,284			$	(36,939	)		$	76,035
Stock based compensation			-				-				-				-				1,448				-				-				1,448
Vested restricted stock			106				1				-				-				(1	)			-				-				-
Vested performance units			95				1				-				-				(1	)			-				-				-
Restricted stock and performance units exchanged for tax withholding			(61	)			(1	)			-				-				(224	)			-				-				(225	)
Non-controlling interest distributions, net			-				-				-				-				-				(36	)			-				(36	)
Net (loss) income			-				-				-				-				-				(2,098	)			1,097				(1,001	)
Balance as of December 31, 2019			7,796			$	78				50			$	1			$	85,834			$	26,150			$	(35,842	)		$	76,221

 

See accompanying Notes to Consolidated Financial Statements. 

 

 

CARBON ENERGY CORPORATION

Consolidated Statements of Cash Flows

(In thousands)

 

		Year Ended December 31,
		2019				2018
Cash flows from operating activities:
Net (loss) income		$	(1,001	)		$	12,779
Items not involving cash:
Depreciation, depletion and amortization			15,757				8,108
Accretion of asset retirement obligations			1,625				868
Unrealized commodity derivative loss (gain)			499				(8,742	)
Warrant derivative gain			-				(225	)
Stock-based compensation expense			1,448				1,133
Investments in affiliates			(77	)			(7,734	)
Amortization of debt costs			846				966
Interest expense paid-in-kind			2,481				-
Other			(57	)			-
Net change in:
Accounts receivable			7,619				545
Prepaid expenses, deposits and other current assets			(809	)			1,067
Accounts payable, accrued liabilities and firm transportation contract obligations			(9,033	)			2,472
Other non-current assets			(442	)			(392	)
Net cash provided by operating activities			18,856				10,845
Cash flows from investing activities:
Development and acquisition of properties and equipment			(8,028	)			(2,995	)
Acquisition of oil and gas properties, asset acquisitions (Note 3)			-				(46,980	)
Acquisition of oil and gas properties, business combinations, net of cash received (Note 3)			-				(20,461	)
Distribution from affiliate			50				-
Proceeds received – disposition of oil and gas properties and other property and equipment			1,408				-
Net cash used in investing activities			(6,570	)			(70,436	)
Cash flows from financing activities:
Vested restricted stock and performance units exchanged for tax withholding			(225	)			(197	)
Proceeds from credit facilities and notes payable			7,000				118,628
Proceeds from preferred shares			-				5,000
Payments on credit facilities and notes payable			(23,708	)			(64,150	)
Payments of debt issuance costs			(149	)			(718	)
(Distributions to) contributions from non-controlling interests, net			(36	)			5,114
Net cash (used in) provided by financing activities			(17,118	)			63,677
Net (decrease) increase in cash and cash equivalents			(4,832	)			4,086
Cash and cash equivalents, beginning of period			5,736				1,650
Cash and cash equivalents, end of period		$	904			$	5,736

 

See Note 16 - Supplemental Cash Flow Disclosure

 

See accompanying Notes to Consolidated Financial Statements.

 

  

CARBON ENERGY CORPORATION

Notes to Consolidated Financial Statements

 

Note 1 - Organization

 

Carbon Energy Corporation (formerly known as Carbon Natural Gas Company) is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of oil, natural gas and natural gas liquids properties located in the United States. The terms “we”, “us”, “our”, the “Company” or “Carbon” refer to Carbon Energy Corporation and our consolidated subsidiaries (described below). The following is an organization chart of the key subsidiaries discussed in this report as of December 31, 2019:

 

 

 

Appalachian and Illinois Basin Operations

 

In the Appalachian and Illinois Basins, operations are conducted by Nytis Exploration Company, LLC (“Nytis LLC”). The following organizational chart illustrates this relationship as of December 31, 2019:

 

 

 

In December 2018, we completed the acquisition of all of the Class A Units of Carbon Appalachian Company, LLC, a Delaware limited liability company (“Carbon Appalachia”), owned by Old Ironside Fund II-A Portfolio Holding Company, LLC, a Delaware limited liability company, and Old Ironside Fund II-B Portfolio Holding Company, LLC, a Delaware limited liability company (collectively, “Old Ironsides”) for a purchase price of $58.2 million, subject to customary and standard purchase price adjustments (“OIE Membership Acquisition”). As a result of the OIE Membership Acquisition, we now hold all of the issued and outstanding ownership interests of Carbon Appalachia, along with its direct and indirect subsidiaries (Carbon Appalachia Group, LLC, Carbon Tennessee Mining Company, LLC, Carbon Appalachia Enterprises, LLC, Carbon West Virginia Company, LLC, Cranberry Pipeline Corporation, Knox Energy, LLC, Coalfield Pipeline Company and Appalachia Gas Services Company, LLC). 

  

Ventura Basin Operations

 

In California, Carbon California Operating Company, LLC conducts operations on behalf of Carbon California Company, LLC, a Delaware limited liability company (“Carbon California”). On February 1, 2018, Yorktown Energy Partners XI, L.P. (“Yorktown”) exercised a warrant, resulting in our aggregate sharing percentage in Carbon California increasing from 17.81% to 56.40% (the “California Warrant”). On May 1, 2018, Carbon California closed an acquisition with Seneca Resources Corporation (the “Seneca Acquisition”). Following the exercise of the California Warrant by Yorktown and the Seneca Acquisition, we own 53.92% of the voting and profits interests and Prudential Legacy Insurance Company of New Jersey and Prudential Insurance Company of America or its affiliates (collectively, “Prudential”) owns 46.08% of the voting and profits interest in Carbon California. As of February 1, 2018, we consolidate Carbon California for financial reporting purposes. The following organizational chart illustrates this relationship as of December 31, 2019:

 

 

Note 2 - Summary of Significant Accounting Policies

 

Principles of Consolidation

 

The consolidated financial statements include the accounts of Carbon Energy Corporation and its consolidated subsidiaries. In addition to Carbon Appalachia and Carbon California, we consolidate 46 partnerships in which we have a controlling interest. We reflect the non-controlling ownership interest of the portion we do not own on our consolidated balance sheets within stockholders’ equity and our consolidated statements of operations.

 

In accordance with established practice in the oil and gas industry, our consolidated financial statements also include our pro-rata share of assets, liabilities, income, lease operating costs and general and administrative expenses of the oil and gas partnerships in which we have a non-controlling interest.

 

We utilize the equity method to account for investments that do not meet the criteria for pro rata consolidation when we have the ability to significantly influence the operating decisions of the investee.

 

All significant intercompany accounts and transactions have been eliminated.

 

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 (“GAAP”) 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, fair value of commodity derivative instruments, fair value of assets acquired and liabilities assumed qualifying as business combinations and asset retirement obligations. Actual results could differ from the estimates and assumptions used.

 

 

Reclassifications

 

Certain prior period balances in the consolidated balance sheets and statements of operations have been reclassified to conform to the current year presentation. Specifically, a portion of credit facilities and notes payable balances as of December 31, 2018 were reclassified from non-current liabilities to current liabilities. The remaining reclassifications include certain immaterial balance sheet and expense accounts. These reclassifications had no impact on net income or stockholders’ equity previously reported.

 

Fair Value of Financial Instruments

 

The carrying value of our cash and cash equivalents, accounts receivables, prepaid expenses, deposits and other current assets and accounts payable and accrued liabilities approximate fair value due to the short maturity of these instruments. The carrying value of our notes payable and credit facilities approximate fair value based on the variable nature of interest rates and current market rates available to us. Commodity derivatives are recorded at fair value.

 

Cash and Cash Equivalents

 

Cash and cash equivalents 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 financial statements. At times, the Company may have cash and cash equivalent balances more than federal insured amounts within their accounts.

 

Accounts Receivable

 

We grant credit to all qualified customers, which potentially subjects us to credit risk resulting from, among other factors, adverse changes in the industries in which we operate and the financial condition of our customers. We continuously monitor collections and payments from our customers and, if necessary, maintain an allowance for doubtful accounts based upon our historical experience and any specific customer collection issues that we have identified.

 

At December 31, 2019 and 2018, we had not identified any collection issues related to our oil and gas operations and consequently no allowance for doubtful accounts was provided for on those dates.

 

Revenue

 

Accounts receivable - Revenue is comprised of oil, natural gas and NGL revenues from producing activities.

 

We recognize 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 we deliver more natural gas than we nominated to deliver to the purchaser and the purchaser pays only for the nominated amount. Conversely, a purchaser imbalance liability occurs when we deliver less natural gas than we nominated to deliver to the purchaser and the purchaser pays for the amount nominated. As of December 31, 2019, and 2018, we had a purchaser imbalance receivable of $956,000 and $551,000, respectively, within accounts receivable-revenue.

 

Joint Interest Billings and Other

 

Our accounts receivable - joint interest billings and other is comprised of receivables due from other exploration and production companies and individuals who own working interests in the properties that we operate. For receivables from joint interest owners, we typically have the ability to withhold future revenues disbursements to recover any non-payment of joint-interest billings.

 

Insurance Receivable

 

Insurance receivable is comprised of insurance claims for the loss of property as a result of wildfires that impacted Carbon California in December 2017. The Company filed claims with its insurance provider. In January 2019, we reached a settlement agreement and received an $800,000 final settlement payment from our insurance provider related to the damage caused by the California wildfires. As of December 31, 2019, we were in receipt of all funds associated with the claims.

 

Revenue Recognition

 

Oil, natural gas and natural gas liquids revenues are recognized when the performance obligation to deliver the production volumes is met and control is transferred to the customer. All product revenues are recognized on the basis of our net revenue interest.

 

  

Oil and natural gas are typically sold in an unprocessed state to third party purchasers. We recognize revenue based on the net proceeds received from the purchaser when control of oil or natural gas passes to the purchaser. For oil sales, control is typically transferred to the purchaser upon receipt at the wellhead or a contractually agreed upon delivery point. Under our natural gas contracts with purchasers, control transfers upon delivery at the wellhead or the inlet of the purchaser’s system. For our other natural gas contracts, control transfers upon delivery to the inlet or to a contractually agreed upon delivery point.

 

Transfer of control drives the presentation of transportation and gathering costs within the accompanying consolidated statements of operations. Transportation and gathering costs incurred prior to control transfer are recorded within the transportation and gathering expense line item on the accompanying consolidated statements of operations, while transportation and gathering costs incurred subsequent to control transfer are recognized as a reduction to the related revenue.

 

We record revenue in the month production is delivered to the purchaser, but settlement statements may not be received until 30 to 90 days after the month of production. As such, we estimate the production delivered and the related pricing. The estimated revenue is recorded within Accounts receivable – Revenue on the consolidated balance sheets. Any differences between our initial estimates and actuals are recorded in the month payment is received from the customer. These differences have not historically been material.

 

Purchaser Concentration

 

We sell our oil, natural gas and natural gas liquids production to various purchasers in the industry. The table below presents purchasers that account for 10% or more of total oil, natural gas, and natural gas liquids sales for the years ended December 31, 2019 and 2018. There are several purchasers in the areas where we sell our production. We do not believe that changing our primary purchasers or a loss of any other single purchaser would materially impact our business.

 

		Year Ended December 31,
Purchaser		2019				2018
Purchaser A			18	%			*
Purchaser B			11	%			*
Purchaser C			*				17	%
Purchaser D			*				16	%
Purchaser E			*				12	%

 

*

less than 10%

 

As of December 31, 2019, none of the above purchasers comprised more than 10% of total accounts receivable. One purchaser’s receivable acquired with the closing of the OIE Membership Acquisition accounted for approximately 10% of accounts receivable as of December 31, 2018.

 

Inventory

 

Inventory includes natural gas, which is recorded at the lower of weighted average cost or market value. Inventory also consists of material and supplies used in connection with the Company’s maintenance, storage and handling and gas that is available for immediate use, referred to as working gas, which are stated at the lower of cost or net realizable value.

 

Accounting for Oil and Gas Operations

 

We use 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 us for our 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. We assess our unproved properties for impairment at least annually.

 

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. 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. 

 

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

 

For the years ended December 31, 2019 and 2018, we did not recognize a ceiling test impairment as our full cost pool did not exceed the ceiling limitations. Future declines in oil and natural gas prices, increases in future operating expenses and future development costs could result in impairments of our oil and gas properties in future periods. Impairment changes are a non-cash charge and accordingly would not affect cash flows but would adversely affect our net income and stockholders’ equity.

 

We capitalize interest in accordance with Financial Accounting Standards Board (“FASB”) ASC 932-835-25, Extractive Activities-Oil and Gas, Interest. Therefore, interest is capitalized for any unusually significant investments in unproved properties or major development projects not currently being depleted. We capitalize the portion of general and administrative costs that is attributable to our acquisition, exploration and development activities.

 

Other Property and Equipment

 

Other property and equipment are recorded at cost or, in the case of assets acquired in a business combination, at fair value. Costs of renewals and improvements that substantially extend the useful lives of assets are capitalized. Maintenance and repair costs which do not extend the useful lives of property and equipment are charged to expense as incurred. Depreciation and amortization are computed using the straight-line method over the estimated useful lives of assets. Office furniture, automobiles, and computer hardware and software are depreciated over three to five years. Buildings are depreciated over 27.5 years, and pipeline facilities and equipment are depreciated over twenty years. Leasehold improvements are capitalized and amortized over the shorter of the lease term or the estimated useful life of the asset.

 

We review our property and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recovered. We look primarily to the estimated undiscounted future cash flows in our assessment of whether or not property and equipment have been impaired.

 

Base Gas

 

Gas that is used to maintain wellhead pressures within the storage fields, referred to as base gas, is recorded in other property and equipment, net on the consolidated balance sheets. Base gas is held in a storage field that is not intended for sale but is required for efficient and reliable operation of the facility.

 

  

Asset Retirement Obligations

 

Our 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 non-current 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 (see Notes 6 and 13).

 

Commodity Derivative Instruments

 

We enter into commodity derivative contracts to manage our exposure to oil and natural gas price volatility with an objective to reduce exposure to downward price fluctuations. Commodity derivative contracts may take the form of futures contracts, swaps, collars or options. We have elected not to designate our 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. Changes in the fair value of commodity derivative contracts are recognized in revenues in the consolidated statements of operations and gains and losses are included within the cash flows from operating activities in the consolidated statements of cash flows. We do not believe we are exposed to credit risk in our derivative activities as the counterparties are established, well-capitalized financial institutions.

 

Stock - Based Compensation

 

For restricted stock, 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). For restricted performance units, once it becomes probable that the performance measure will be achieved, expense is recognized over the remainder of the performance period.

 

Income Taxes

 

We account 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 basis, 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.

 

We account 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.

 

Earnings Per Common Share

 

Basic earnings (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders for the period by the basic weighted average number of common shares outstanding during the period. Diluted earnings (loss) per common share includes potentially issuable shares consisting primarily of non-vested restricted stock and contingent restricted performance units, using the treasury stock method. In periods when we report a net loss, all common stock equivalents are excluded from the calculation of diluted weighted average shares outstanding because they would have an anti-dilutive effect, meaning the loss per share would be reduced.

 

  

Recently Adopted Accounting Pronouncement

  

On January 1, 2019, we adopted Accounting Standards Update No. 2016-02, Leases (“Topic 842”) (ASU 2016-02), as amended, which supersedes the lease accounting guidance under Topic 840, and generally requires lessees to recognize operating and financing lease liabilities and corresponding right-of-use assets on the balance sheet and to provide enhanced disclosures surrounding the amount, timing and uncertainty of cash flows arising from leasing arrangements. We adopted the new guidance using the modified retrospective transition approach by applying the new standard to all leases existing at the date of initial application and not restating comparative periods. The most significant impact was the recognition of right-of-use assets and lease liabilities for operating leases. See Note 8 for further information on our implementation of this standard.

 

Note 3 - Acquisitions

 

Majority Control of Carbon Appalachia

 

On December 31, 2018, we acquired all of Old Ironsides’ Class A Units of Carbon Appalachia for approximately $58.2 million, representing approximately 72.76% share ownership. We paid $33.0 million in cash and delivered promissory notes of approximately $25.2 million to Old Ironsides (the “Old Ironsides Notes”). See Note 7 for additional information.

 

The OIE Membership Acquisition was accounted for as a business combination in accordance with ASC 805, Business Combinations (“ASC 805”). We finalized the determination of the fair values of the assets acquired and liabilities assumed in the fourth quarter of 2019. There were no material changes in the fair values of the assets acquired and the liabilities assumed from the preliminary amounts. The following table summarizes the final fair values:

 

		Amount  (in thousands)
Cash consideration		$	33,000
Old Ironsides Notes			25,194
Fair value of previously held equity interest			14,029
Fair value of business acquired		$	72,223

  

Assets acquired and liabilities assumed are as follows:

 

		Amount (in thousands)
Cash		$	12,283
Accounts receivable:
Revenue			12,834
Trade receivable			1,941
Commodity derivative asset			198
Inventory			2,022
Prepaid expenses, deposits, and other current assets			456
Oil and gas properties:
Proved			107,694
Unproved			1,869
Other property and equipment, net			15,441
Other non-current assets			514
Accounts payable and accrued liabilities			(20,468	)
Due to related parties			(236	)
Firm transportation contract obligations			(18,724	)
Asset retirement obligations			(5,626	)
Notes payable			(37,975	)
Total net assets acquired		$	72,223

 

  

On the date of the acquisition, we derecognized our equity investment in Carbon Appalachia and recognized a gain of approximately $1.3 million based on the fair value of our previously held interest compared to its carrying value, which is recorded in investments in affiliates in our consolidated statement of operations for the year ended December 31, 2018.

 

Consolidation of Carbon Appalachia and OIE Membership Acquisition Pro Forma Results of Operations (Unaudited)

 

Below are unaudited pro forma consolidated results of operations for the year ended December 31, 2018, as though the OIE Membership Acquisition had been completed as of January 1, 2018:

 

		Year Ended December 31,
(in thousands, except per share amounts)		2018 (unaudited)
Revenue		$	136,592
Net income before non-controlling interests		$	11,320
Net income attributable to non-controlling interests		$	4,375
Net income attributable to controlling interests before preferred shares		$	5,596
Net income per share, basic		$	0.74
Net income per share, diluted		$	0.69

 

Liberty Acquisition

 

On July 11, 2018, we completed an acquisition of 54 operated oil and gas wells covering approximately 55,000 gross acres (22,000 net) and associated mineral interests in the Appalachian Basin for a purchase price of $3.0 million (the “Liberty Acquisition”).  The Liberty Acquisition increased our working interest in the acquired wells from 60% to 100%.  The Liberty Acquisition was funded through borrowings under our previous credit facility. The Liberty Acquisition was accounted for as a non-significant asset acquisition.

 

Majority Control of Carbon California

 

The acquisition of additional ownership interest in Carbon California on February 1, 2018, was accounted for as a step acquisition in which we obtained control in accordance with ASC 805 (referred to herein as the “Carbon California Acquisition”). We recognized 100% of the identifiable assets acquired, liabilities assumed and the non-controlling interest at their respective fair value as of the date of the acquisition. We exchanged 1,527,778 common shares at a fair value of approximately $8.3 million ($5.45 per share), for 11,000 Class A Units of Carbon California, representing a 38.59% profits ownership interest in Carbon California. We followed the fair value method to allocate the consideration transferred to the identifiable net assets acquired and non-controlling interest as follows: 

 

		Amount  (in thousands)
Fair value of Carbon common shares transferred as consideration		$	8,327
Fair value of non-controlling interest			16,466
Fair value of previously held interest			7,243
Fair value of contribution associated with acquisition of Yorktown’s interest in Carbon California			8,637
Fair value of business acquired		$	40,673

 

  

Assets acquired and liabilities assumed are as follows:

 

		Amount (in thousands)
Cash		$	275
Accounts receivable:
Joint interest billings and other			690
Receivable - related party			1,610
Prepaid expenses, deposits, and other current assets			1,723
Oil and gas properties:
Proved			65,114
Unproved			1,495
Other property and equipment, net			877
Other non-current assets			475
Accounts payable and accrued liabilities			(6,054	)
Commodity derivative liability - current			(916	)
Commodity derivative liability - non-current			(1,729	)
Asset retirement obligations - current			(384	)
Asset retirement obligations - non-current			(2,537	)
Subordinated Notes, related party, net			(8,874	)
Senior Revolving Notes, related party			(11,000	)
Notes payable			(92	)
Total net assets acquired		$	40,673

  

On the date of the acquisition, we derecognized our equity investment in Carbon California and recognized a gain of approximately $5.4 million based on the fair value of our previously held interest compared to its carrying value.

 

During the fourth quarter of 2018, the Company finalized the determination of fair value and purchase price allocation related to the Carbon California Acquisition.  Based on the final valuation received, the allocation of fair value exceeded the consideration by $8.6 million, which has been reflected in equity as a capital contribution from Yorktown who held a significant membership interest in Carbon California and is the Company’s largest stockholder.

 

Seneca Acquisition

 

On May 1, 2018, Carbon California acquired approximately 309 oil wells and approximately 6,800 gross acres (6,600 net) of oil and gas leases, and fee interests in and to certain lands, situated in the Ventura Basin, together with associated pipelines, facilities, equipment and other property rights from Seneca Resources Corporation (“Seneca Acquisition”) for a purchase price of $43.0 million. We contributed approximately $5.0 million to Carbon California to fund our portion of the purchase price through the issuance of 50,000 shares of preferred stock to Yorktown. Prudential also contributed $5.0 million to fund its share of the equity portion of the purchase price. Carbon California funded the remaining purchase price from cash, increased borrowings under the Carbon California Senior Revolving Notes and $3.0 million in proceeds from the issuance of Senior Subordinated Notes.

 

The Seneca Acquisition was accounted for as an asset acquisition as substantially all of the value related to proved oil and gas properties.

 

Consolidation of Carbon California and Seneca Acquisition Pro Forma Results of Operations (Unaudited)

 

Below are unaudited pro forma consolidated results of operations for the year ended December 31, 2018, as though the Carbon California Acquisition and the Seneca Acquisition had been completed as of January 1, 2018:

 

(in thousands, except per share amounts)		Year Ended December 31, 2018 (unaudited)
Revenue		$	33,256
Net income before non-controlling interests		$	5,232
Net loss attributable to non-controlling interests			(2,334	)
Net income attributable to controlling interests		$	7,566
Net income per share (basic)		$	1.00
Net income per share (diluted)		$	0.96

 

  

Note 4 - Property and Equipment, Net

 

Property and equipment, net consists of the following:

 

		As of December 31,
(in thousands)		2019				2018
Oil and gas properties:
Proved oil and gas properties		$	351,488			$	347,059
Unproved properties			4,872				5,416
Accumulated depreciation, depletion, amortization and impairment			(109,344	)			(98,604	)
Oil and gas properties, net			247,016				253,871
Pipeline facilities and equipment			12,814				12,714
Base gas			1,937				2,122
Furniture and fixtures, computer hardware and software, and other equipment			6,762				6,649
Accumulated depreciation and amortization			(5,529	)			(3,922	)
Other property and equipment, net			15,984				17,563
Total property and equipment, net		$	263,000			$	271,434

 

Unproved properties not subject to depletion consist principally of leasehold acquisition costs in the following areas:

 

		As of December 31,
(in thousands)		2019				2018
Ventura Basin:
California		$	1,602			$	1,595
Illinois Basin:
Indiana			432				432
Illinois			136				136
Appalachian Basin:
Kentucky			461				920
Ohio			66				66
Tennessee			1,869				1,869
West Virginia			306				398
Total unproved properties		$	4,872			$	5,416

 

Unproved properties are assessed for impairment at least annually. During the year ended December 31, 2019, approximately $1.0 million of expired leasehold costs were reclassified into proved property. During the year ended December 31, 2018, there were no leasehold costs reclassified into proved property.

 

We capitalized overhead applicable to acquisition, development and exploration activities, primarily in California, of approximately $790,000 and $337,000 for the years ended December 31, 2019 and 2018, respectively.

 

Depletion expense related to oil and gas properties for the years ended December 31, 2019 and 2018 was approximately $14.1 million and $7.3 million, respectively.

 

 

Note 5 - Accounts Payable and Accrued Liabilities

 

Accounts payable and accrued liabilities consist of the following:

 

		As of December 31,
(in thousands)		2019				2018
Accounts payable		$	9,875			$	7,670
Oil and gas revenue suspense			3,620				2,675
Gathering and transportation payables			1,877				1,774
Production taxes payable			3,212				1,860
Accrued lease operating costs			664				3,155
Accrued ad valorem taxes-current			4,407				3,474
Accrued general and administrative expenses			3,260				3,111
Asset retirement obligations-current			5,021				3,099
Accrued interest			1,335				955
Accrued gas purchases			1,392				5,441
Other liabilities			494				1,602
Total accounts payable and accrued liabilities		$	35,157			$	34,816

 

Note 6 - Asset Retirement Obligations

 

The following table is a reconciliation of the ARO:

 

		December 31,
(in thousands)		2019				2018
Balance at beginning of year		$	22,310			$	7,357
Accretion expense			1,625				868
Additions and revisions			294				-
Obligations discharged with divestitures			(1,694	)			-
Change in estimate of cash outflow			-				361
Additions from Carbon California (Note 3)			-				2,921
Additions from Seneca Acquisition (Note 3)			-				5,132
Additions from Liberty Acquisition (Note 3)			-				45
Additions from OIE Membership Acquisition			-				5,626
Balance at end of year		$	22,535			$	22,310
Less: Current portion			(5,021	)			(3,099	)
Non-current portion		$	17,514			$	19,211

 

See Note 2 for additional details on the ARO.

 

Note 7 - Credit Facilities and Notes Payable

 

The table below summarizes the outstanding credit facilities and notes payable:

 

(in thousands)		December 31, 2019				December 31, 2018
2018 Credit Facility – revolver		$	69,150			$	69,150
2018 Credit Facility – term note			5,833				15,000
Old Ironsides Notes			25,675				25,065
Other debt			45				57
Total debt			100,703				109,272
Less: unamortized debt discount			(45	)			(134	)
Total credit facilities and notes payable			100,658				109,138
Current portion of credit facilities and notes payable			(5,788	)			(11,910	)
Non-current debt, net of current portion and unamortized debt discount		$	94,870			$	97,228

 

 

Carbon Appalachia

 

2018 Credit Facility

 

In connection with and concurrently with the closing of the OIE Membership Acquisition, the Company and its subsidiaries amended and restated our prior credit facilities and entered into a $500.0 million senior secured asset-based revolving credit facility maturing December 31, 2022 and a $15.0 million term loan maturing in 2020 (the “2018 Credit Facility”). The 2018 Credit Facility includes a sublimit of $1.5 million for letters of credit. The borrowers under the 2018 Credit Facility are Carbon Appalachia Enterprises, LLC (“CAE”) and various other subsidiaries of the Company (including Nytis USA, together with CAE, the “Borrowers”). Under the 2018 Credit Facility, Carbon Energy Corporation is neither a borrower nor a guarantor. The initial borrowing base under the 2018 Credit Facility was $75.0 million and remained so as of December 31, 2019.

 

The 2018 Credit Facility is guaranteed by each existing and future direct or indirect subsidiary of the Borrowers and certain other subsidiaries of the Company (subject to various exceptions) and the obligations under the 2018 Credit Facility are secured by essentially all tangible, intangible and real property (subject to certain exclusions).

 

Interest accrues on borrowings under the 2018 Credit Facility at a rate per annum equal to either (i) the base rate plus a margin equal to 0.25% - 0.75% depending on the utilization percentage or (ii) the Adjusted London Interbank Offered Rate (“LIBOR”) plus a margin equal to 2.75% - 3.75% depending on the utilization percentage, at the Borrowers’ option. The Borrowers are obligated to pay certain fees and expenses in connection with the 2018 Credit Facility, including a commitment fee for any unused amounts of 0.50% and an origination fee of 0.50%. Loans under the 2018 Credit Facility may be prepaid without premium or penalty.

  

The 2018 Credit Facility also provides for a $15.0 million term loan which bears interest at a rate of 6.25% and is payable in 18 equal monthly installments beginning February 1, 2019 with the last payment due on July 1, 2020.

 

The 2018 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 distribution on, or repurchase of, equity; (vi) make certain investments; (vii) enter into certain transactions with their affiliates; (viii) enter in sale-leaseback transactions; (ix) make optional or voluntary payment of debt other than obligations under the 2018 Credit Facility; (x) change the nature of their business; (xi) change their fiscal year or make changes to the accounting treatment or reporting practices; (xii) amend their 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 2018 Credit Facility requires the Borrowers’ compliance, on a consolidated basis, with a maximum Net Debt (all debt of the Borrowing Parties minus all unencumbered cash and cash equivalents of the Borrowers not to exceed $3.0 million) / EBITDAX (as defined) ratio of 3.50 to 1.00 and a current ratio, as defined, minimum of 1.00 to 1.00, tested quarterly, commencing with the quarter ending March 31, 2019.

 

In August 2019, we amended the 2018 Credit Facility, effective October 1, 2019, to restrict the aging of our accounts payable to 90 days or less, maintain minimum liquidity of $3.0 million and require the sale of certain non-core assets by December 31, 2019. 

 

In February 2020, we amended the 2018 Credit Facility to eliminate the minimum liquidity requirement and reduce the borrowing base to $73.0 million, with subsequent borrowing base reductions totaling $6.0 million scheduled through May 1, 2020. Also, in connection with this amendment, the lenders agreed to waive our noncompliance with the hedging requirement for the fiscal quarter ended September 30, 2019 and waive the asset sale covenant included in the amendment from August 2019.

 

 

As of December 31, 2019, there was approximately $69.2 million in outstanding borrowings and $5.0 million of additional borrowing capacity under the 2018 Credit Facility. After considering the waivers granted in the February 2020 amendment, we were in compliance with our December 31, 2019 financial covenants.

 

As a result of borrowing base reductions in 2020 discussed above and currently depressed oil and natural gas prices, certain of our covenants under the 2018 Credit Facility may be stressed and may require negotiations and adjustments with our lenders. While we have historically been successful in renegotiating covenant requirements with our lenders, there can be no assurance that we will be able to do so successfully in the future. The Company believes given these circumstances it is appropriate to keep the borrowings associated with the 2018 Credit Facility as non-current.

 

The terms of the 2018 Credit Facility require us to enter into derivative contracts at fixed pricing for a certain percentage of our production. We are party to International Swaps and Derivatives Association Master Agreements (“ISDA Master Agreements”) that establish standard terms for the derivative contracts and inter-creditor agreements with the lenders whereby any credit exposure related to the derivative contracts entered into by us is secured by the collateral and backed by the guarantees supporting the 2018 Credit Facility.

 

Fees paid in connection with the 2018 Credit Facility totaled approximately $824,000, of which $134,000 was associated with the term loan. The current portion of unamortized fees associated with the credit facility is included in prepaid expenses, deposits and other current assets and the non-current portion is included in other non-current assets. The unamortized portion associated with the term loan was $45,000 as of December 31, 2019 and is directly offset against the loan in current liabilities. As of December 31, 2019, we had unamortized deferred issuance costs of approximately $519,000 associated with the 2018 Credit Facility. During the years ended December 31, 2019 and 2018, we amortized approximately $260,000 and $786,000, respectively, as interest expense associated with the 2018 Credit Facility.

 

Old Ironsides Notes

 

On December 31, 2018, as part of the OIE Membership Acquisition, we delivered unsecured, promissory notes in the aggregate original principal amount of approximately $25.2 million to Old Ironsides (the “Old Ironsides Notes”). The Old Ironsides Notes bear interest at 10.0% per annum and have a term of five years, the first three of which require interest-only payments at the end of each calendar quarter beginning with the quarter ending March 31, 2019. At the end of the three-year interest-only period, the then current outstanding principal balance and interest is to be paid in 24 equal monthly payments. The Old Ironsides Notes also require mandatory prepayments upon the occurrence of certain subsequent liquidity events. A mandatory, one-time principal reduction payment in the aggregate amount of $2.0 million was made to Old Ironsides on February 1, 2019. Subsequent to the closing of the OIE Membership Acquisition, Old Ironsides ceased to be a related party.

 

The interest payable under the Old Ironsides Notes can be paid-in-kind at the election of the Company. This provision allows the Company to increase the principal balance associated with the Old Ironsides Notes. This election creates a second tranche of principal, which bears interest at 12.0% per annum. For the year ended December 31, 2019, the Company elected payment-in-kind interest of approximately $2.5 million.

 

Carbon California

  

The table below summarizes the outstanding notes payable – related party:

 

(in thousands)		December 31, 2019				December 31, 2018
Senior Revolving Notes, related party, due February 15, 2022		$	33,000			$	38,500
Subordinated Notes, related party, due February 15, 2024			13,000				13,000
Total principal			46,000				51,500
Less: Deferred notes costs			(175	)			(235	)
Less: unamortized debt discount			(1,084	)			(1,346	)
Total notes payable – related party		$	44,741			$	49,919

 

  

Senior Revolving Notes, Related Party

 

On February 15, 2017, Carbon California entered into a Note Purchase Agreement (the “Note Purchase Agreement”) for the issuance and sale of Senior Secured Revolving Notes to Prudential with an initial revolving borrowing capacity of $25.0 million which mature on February 15, 2022 (the “Senior Revolving Notes”). Carbon Energy Corporation is not a guarantor of the Senior Revolving Notes. The closing of the Note Purchase Agreement on February 15, 2017 resulted in the sale and issuance by Carbon California of Senior Revolving Notes in the principal amount of $10.0 million. The maximum principal amount available under the Senior Revolving Notes is based upon the borrowing base attributable to Carbon California’s proved oil and gas reserves which is to be determined at least semi-annually. As of December 31, 2019, the borrowing base was $45.0 million, of which $33.0 million was outstanding.  

 

Carbon California may elect to incur interest at either (i) 5.50% plus LIBOR or (ii) 4.50% plus the Prime Rate (which is defined as the interest rate published daily by JPMorgan Chase Bank, N.A.). As of December 31, 2019, the effective borrowing rate for the Senior Revolving Notes was 7.10%. In addition, the Senior Revolving Notes include a commitment fee for any unused amounts at 0.50% as well as an annual administrative fee of $75,000, payable on February 15 each year.

 

The Senior Revolving Notes are secured by all the assets of Carbon California. The Senior Revolving Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated proved developed production for year one, two and three at a rate of 75%, 65% and 50%, respectively. Carbon California may make principal payments in minimum installments of $500,000. Distributions to equity members are generally restricted.

 

Carbon California incurred fees directly associated with the issuance of the Senior Revolving Notes and amortizes these fees over the life of the Senior Revolving Notes. The current portion of these fees are included in prepaid expenses, deposits and other current assets and the non-current portion is included in other non-current assets for a combined value of approximately $599,000 as of December 31, 2019. For the years ended December 31, 2019 and 2018, Carbon California amortized fees of $273,000 and $217,000, respectively.

 

Subordinated Notes, Related Party

 

On February 15, 2017, Carbon California entered into a Securities Purchase Agreement (the “Securities Purchase Agreement”) with Prudential Capital Energy Partners, L.P. for the issuance and sale of Subordinated Notes due February 15, 2024, bearing interest of 12.0% per annum (the “Subordinated Notes”). Carbon Energy Corporation is not a guarantor of the Subordinated Notes. The closing of the Securities Purchase Agreement on February 15, 2017 resulted in the sale and issuance by Carbon California of Subordinated Notes in the original principal amount of $10.0 million, all of which remains outstanding as of December 31, 2019.

  

Prudential received an additional 1,425 Class A Units, representing 5.0% of the total sharing percentage, for the issuance of the Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding Subordinated Notes of $10.0 million. The Company then allocated the non-cash value of the units of approximately $1.3 million, which was recorded as a discount to the Subordinated Notes. As of December 31, 2019, Carbon California has an outstanding discount of $735,000, which is presented net of the Subordinated Notes within Notes payable-related party on the consolidated balance sheets. During the years ended December 31, 2019 and 2018, Carbon California amortized fees of $178,000 and $58,000, respectively, associated with the Subordinated Notes.

 

The Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production for year one, two and three at a rate of 67.5%, 58.5% and 45%, respectively.

 

Prepayment of the Subordinated Notes is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is not subject to a prepayment fee after February 17, 2020. Distributions to equity members are generally restricted. 

 

2018 Subordinated Notes, Related Party

 

On May 1, 2018, Carbon California entered into an agreement with Prudential for the issuance and sale of $3.0 million in subordinated notes due February 15, 2024, bearing interest of 12.0% per annum (the “2018 Subordinated Notes”), of which $3.0 million remains outstanding as of December 31, 2019.

 

  

Prudential received 585 Class A Units, representing an approximate 2.0% additional sharing percentage, for the issuance of the 2018 Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding 2018 Subordinated Notes of $3.0 million. The Company then allocated the non-cash value of the units of approximately $490,000, which was recorded as a discount to the 2018 Subordinated Notes. As of December 31, 2019, Carbon California had an outstanding discount of $349,000 associated with these notes, which is presented net of the 2018 Subordinated Notes within Notes payable - related party on the consolidated balance sheet. During the year ended December 31, 2019 and 2018, Carbon California amortized fees of $84,000 and $57,000, respectively, associated with the 2018 Subordinated Notes.

 

The 2018 Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production for year one, two and three at a rate of 67.5%, 58.5% and 45%, respectively.

 

Prepayment of the 2018 Subordinated Notes is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is not subject to a prepayment fee after February 17, 2020. Distributions to equity members are generally restricted.

 

Restrictions and Covenants

 

The Senior Revolving Notes, Subordinated Notes and 2018 Subordinated Notes contain affirmative and negative covenants that, among other things, limit Carbon California’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 our affiliates; (viii) enter into sales-leaseback transactions; (ix) make optional or voluntary payments of debt; (x) change the nature of our business; (xi) change our fiscal year to make changes to the accounting treatment or reporting practices; (xii) amend constituent documents; and (xiii) enter into certain hedging transactions.

 

In December 2019, Carbon California amended the Senior Revolving Notes, the Subordinated Notes and the 2018 Subordinated Notes to amend the total leverage ratio and senior leverage ratio, effective September 30, 2019. The Senior Revolving Notes were also amended to provide a mechanism to determine a successor reference rate to LIBOR.

 

The affirmative and negative covenants are subject to various exceptions, including basket amounts and acceptable transaction levels. In addition, (i) the Senior Revolving Notes require at December 31, 2019 Carbon California’s compliance with (A) a maximum Debt/EBITDA ratio of 4.5 to 1.0 (B) a maximum Senior Revolving Notes/EBITDA ratio of 3.5 to 1.0 and (C) a minimum interest coverage ratio of 2.0 to 1 and (ii) the Subordinated Notes require at December 31, 2019 Carbon California’s compliance with (A) a maximum Debt/EBITDA ratio of 5.18 to 1.0, (B) a maximum Senior Revolving Notes/EBITDA ratio of 4.03 to 1.0, (C) a minimum interest coverage ratio of 1.6 to 1.0, (D) an asset coverage test whereby indebtedness may not exceed the product of 0.65 times Adjusted PV-10 of proved developed reserves set forth in the most recent reserve report, (E) maintenance of a minimum borrowing base of $30.0 million under the Senior Revolving Notes and (F) a minimum current ratio of 0.85 to 1.00.

 

As of December 31, 2019, Carbon California was in compliance with its financial covenants.

 

Note 8 - Leases

 

On January 1, 2019, we adopted Topic 842. Results for reporting periods beginning January 1, 2019 are presented in accordance with Topic 842, while prior period amounts are reported in accordance with Topic 840 – Leases. On January 1, 2019, we recognized approximately $7.7 million in right-of-use assets and approximately $7.7 million in lease liabilities, representing the present value of minimum payment obligations associated with compressor, vehicle, and office space operating leases with non-cancellable lease terms in excess of one year. We do not have any finance leases, nor are we the lessor in any leasing arrangements. We have elected certain practical expedients available under Topic 842 including those that permit us to (i) account for lease and non-lease components in our contracts as a single lease component for all asset classes; (ii) not evaluate existing and expired land easements; (iii) not apply the recognition requirements of Topic 842 to leases with a lease term of twelve months or less; and (iv) retain our existing lease assessment and classification. As such, there was no cumulative-effect adjustment to retained earnings required at January 1, 2019.

 

  

The lease amounts disclosed herein are presented on a gross basis. A portion of these costs may have been or will be billed to other working interest owners, and our net share of these costs, once paid, are or will be included in lease operating expenses, pipeline operating expenses or general and administrative expenses, as applicable.

 

Our right-of-use assets and lease liabilities are recognized at their discounted present value on the balance sheet. All leases recognized on our consolidated balance sheet as of December 31, 2019 are classified as operating leases, which include leases related to the asset classes reflected in the table below:

 

(in thousands)		Right-of-Use Assets				Lease Liability
Compressors		$	3,282			$	3,282
Corporate leases			2,065				2,083
Vehicles			757				643
Total		$	6,104			$	6,008

 

We recognize lease expense on a straight-line basis excluding short-term and variable lease payments which are recognized as incurred. Short-term lease cost represents payments for leases with a lease term of twelve months or less, excluding leases with a term of one month or less. Short-term leases include certain compressors and vehicles that have a non-cancellable lease term of less than one year.

 

The following table summarizes the components of our gross operating lease costs incurred during the year ended December 31, 2019:

 

(in thousands)		Amount
Operating lease cost		$	2,116
Short-term lease cost			629
Total lease cost		$	2,745

  

We do not have any leases with an implicit interest rate that can be readily determined. As a result, we calculate collateralized incremental borrowing rates to use as discount rates. We utilize the benchmark rates defined in our credit facilities, and adjust for facility utilization and term considerations, to establish collateralized incremental borrowing rates.

 

Our weighted-average lease term and discount rate used are as follows:

 

		December 31, 2019
Weighted-average lease term (years)			3.59
Weighted-average discount rate			6.4	%

 

The following table summarizes supplemental cash flow information related to operating leases: 

 

(in thousands)		Year Ended December 31, 2019
Cash paid for operating leases		$	2,212
Right-of-use assets obtained in exchange for operating lease obligations		$	465

 

   

Minimum future commitments by year for our long-term operating leases as of December 31, 2019 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet as follows:

 

(in thousands)		Amount
2020		$	1,960
2021			1,902
2022			1,704
2023			1,157
2024			11
Thereafter			-
Total future minimum lease payments		$	6,734
Less: imputed interest			(726	)
Total lease liabilities		$	6,008

 

Note 9 - Revenue

 

Oil, Natural Gas and Natural Gas Liquid Sales

 

We sell oil and natural gas products in the United States primarily within two regions of the United States: Appalachia and Illinois Basins and the Ventura Basin. We enter into contracts that generally include one type of distinct product in variable quantities and priced based on a specific index related to the type of product. Most of our contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions.

 

Transportation and Handling

 

We generally purchase natural gas from producers at the wellhead or other receipt points, gather the wellhead natural gas through our gathering systems, and then sell the natural gas based on published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of natural gas or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, regardless of the actual amount of the sales proceeds we receive. Our revenues under percent-of-proceeds/index arrangements generally correlate to the price of natural gas. Under fee-based arrangements, we receive a fee for storing natural gas. The storage revenues earned are directly related to the volume of natural gas that flows through our systems and are not directly dependent on commodity prices.

 

Marketing Gas Sales

 

We sell production purchased from third parties as well as production from our own oil and gas producing properties. Marketing gas sales are recognized on a gross basis as we purchase and take control of the gas prior to sale and are the principal in the transaction.

 

The following tables present our disaggregated revenue by primary region within the United States and major product line (in thousands):

 

		Appalachian and Illinois Basins								Ventura Basin								Total
		Year Ended December 31,								Year Ended December 31,								Year Ended December 31,
		2019				2018				2019				2018				2019				2018
Natural gas sales		$	55,279			$	14,768			$	1,189			$	1,250			$	56,468			$	16,018
Natural gas liquids sales			-				-				578				1,143				578				1,143
Oil sales			5,805				4,963				30,990				25,928				36,795				30,891
Transportation and handling			1,928				-				-				-				1,928				-
Marketing gas sales			16,920				-				-				-				16,920				-
Total		$	79,932			$	19,731			$	32,757			$	28,321			$	112,689			$	48,052

 

  

Note 10 - Stock-Based Compensation Plans and Employee Benefit Plans

 

Carbon Stock Incentive Plans

 

We have three stock plans, the Carbon 2011 Stock Incentive Plan, the Carbon 2015 Stock Incentive Plan and the Carbon 2019 Long Term Incentive Plan (collectively the “Carbon Plans”). The Carbon 2019 Long Term Incentive Plan was approved by the Company’s stockholders in May 2019. The Carbon Plans provide for the issuance of approximately 1.6 million shares of common stock to our officers, directors, employees or consultants eligible to receive the awards under the Carbon Plans.

 

The Carbon Plans provide for the granting of incentive stock options, non-qualified stock options, restricted stock awards, performance awards and phantom stock awards, or a combination of the foregoing, to employees, officers, directors or consultants, provided that only employees may be granted incentive stock options and directors may only be granted restricted stock awards and phantom stock awards.

  

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 us or the date their membership on the Board of Directors is terminated other than for cause. We recognize compensation expense for these restricted stock grants based on the grant date fair value. The following table shows a summary of our unvested restricted stock under the Carbon Plans as of December 31, 2019 and 2018 as well as activity during the years then ended:

 

						Weighted Average
		Number of Shares				Grant Date Fair Value
Restricted stock awards, unvested, January 1, 2018			269,997			$	7.54
Granted			106,000				9.80
Vested			(59,550	)			6.82
Forfeited			(2,240	)			7.41
Restricted stock awards, unvested, December 31, 2018			314,207			$	8.40
Granted			99,000				10.00
Vested			(105,628	)			6.75
Forfeited			(6,682	)			9.74
Restricted stock awards, unvested, December 31, 2019			300,897			$	9.41

 

Compensation costs recognized for these restricted stock grants were approximately $811,000 and $725,000 for the years ended December 31, 2019 and 2018, respectively. As of December 31, 2019, there was approximately $1.5 million of unrecognized compensation costs related to these restricted stock grants which we expect to recognize over the next 6.3 years.

 

 

Restricted Performance Units

 

Performance units represent a contractual right to receive one share of our common stock subject to the terms and conditions of the agreements, including the achievement of certain performance measures over a defined period of time as well as, in some cases, continued service requirements. The following table shows a summary of our unvested performance units as of December 31, 2019 and 2018 as well as activity during the years then ended:

 

		Number
		of Shares
Restricted performance units, unvested, January 1, 2018			258,811
Granted			136,159
Vested			(108,484	)
Forfeited			(6,610	)
Restricted performance units, unvested, December 31, 2018			279,876
Granted			101,864
Vested			(95,451	)
Forfeited			(11,084	)
Restricted performance units, unvested, December 31, 2019			275,205

 

We account for the performance units granted during 2017 through 2019 at their fair value determined at the date of grant, which were $7.20, $9.80 and $10.00 per share, respectively. The final measurement of compensation cost will be based on the number of performance units that ultimately vest. At December 31, 2019, we estimated that none of the performance units granted in 2019 and 2018 would vest, and, accordingly, no compensation cost has been recorded for these performance units. At December 31, 2019, we estimated that it was probable that the performance units granted in 2015, 2016 and 2017 would vest and therefore compensation costs of approximately $637,000 and $408,000 related to these performance units were recognized for the years ended December 31, 2019 and 2018, respectively. As of December 31, 2019, compensation costs related to the performance units granted in 2015, 2016 and 2017 have been fully recognized. As of December 31, 2019, if a change in control and other performance provisions pursuant to the terms and conditions of these award agreements were met in full, the estimated unrecognized compensation cost related to unvested performance units would be approximately $3.2 million.

 

401(k) Plan

 

We have a 401(k) plan available to eligible employees. The plan provides for 6.0% matching which vests immediately. For the years ended December 31, 2019 and 2018, we contributed approximately $527,000 and $441,000, respectively, for 401(k) contributions and related administrative expenses.

 

  

Note 11 - Earnings (Loss) Per Common Share

 

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

 

		Year Ended December 31,
(in thousands, except per share amounts)		2019				2018
Net income attributable to controlling interests before preferred shares		$	1,097			$	8,404
Less: beneficial conversion feature			-				1,125
Less: net income attributable to preferred shares – preferred return			300				224
Net income attributable to common stockholders, basic			797				7,055
Less: warrant derivative gain			-				225
Net income attributable to common stockholders, diluted		$	797			$	6,830
Weighted-average number of common shares outstanding, basic			7,794				7,525
Add dilutive effects of non-vested shares of restricted stock and restricted performance units			301				314
Weighted-average number of common shares outstanding, diluted			8,095				7,839
Net income per common share, basic		$	0.10			$	0.94
Net income per common share, diluted		$	0.10			$	0.87

 

For the years ended December 31, 2019 and 2018, approximately 275,000 and 280,000 restricted performance units subject to future contingencies were excluded from the computation of basic and diluted earnings per share.

 

Series B Convertible Preferred Stock – Related Party

 

In connection with the closing of the Seneca Acquisition, we raised $5.0 million through the issuance of 50,000 shares of Series B Convertible Preferred Stock, par value $0.01 per share (“Preferred Stock”) to Yorktown. The Preferred Stock converts into common stock at the election of the holder or will automatically convert into shares of our common stock upon completion of a qualifying equity financing event. The number of shares of common stock issuable upon conversion is dependent upon the price per share of common stock issued in connection with any such qualifying equity financing but has a floor conversion price equal to $8.00 per share. The conversion ratio at which the Preferred Stock will convert into common stock is equal to an amount per share of $100 plus all accrued but unpaid dividends payable in respect thereof divided by the greater of $8.00 per share or the price that is 15.0% less than the lowest price per share of shares sold to the public in the next equity financing. Using the floor of $8.00 per share would yield 12.5 shares of common stock for every unit of Preferred Stock. The conversion price will be proportionately increased or decreased to reflect changes to the outstanding shares of common stock, such as the result of a combination, reclassification, subdivision, stock split, stock dividend or other similar transaction involving the common stock. Additionally, after the third anniversary of the issuance of the Preferred Stock, we have the option to redeem the shares for cash.

 

The Preferred Stock accrues cash dividends at a rate of 6.0% of the initial issue price of $100 per share per annum. The holders of the Preferred Stock are entitled to the same number of votes of common stock that such share of Preferred Stock would represent on an as converted basis. The holders of the Preferred Stock receive liquidation preference based on the initial issue price of $100 per share plus a preferred return over common stockholders and the holders of any junior ranking stock. The preferred return was approximately $524,000 and $224,000 as of December 31, 2019 and 2018, respectively.

 

  

Note 12 - Income Taxes

 

The provision for income taxes consists of the following:

 

		Year Ended
		December 31,
(in thousands)		2019				2018
Current income tax benefit		$	-			$	-
Deferred income tax expense (benefit)			895				(590	)
Change in valuation allowance			(895	)			590
Total income tax benefit		$	-			$	-

 

The effective income tax rate for the years ended December 31, 2019 and 2018 differed from the statutory U.S. federal income tax rate as follows:

 

		Year Ended
		December 31,
		2019				2018
Federal income tax rate			21.0	%			21.0	%
State income taxes, net of federal benefit			4.9				4.9
Permanent differences			(3.3	)			(1.2	)
Non-controlling interest in consolidated partnerships			(46.2	)			(11.4	)
True-up of prior year depletion in excess of basis			(6.5	)			1.3
Stock-based compensation deficiency			(16.0	)			1.1
Purchase accounting adjustments			(45.0	)			(22.9	)
Rate changes of prior year deferred			1.8				(0.5	)
True-up of prior year deferred			-				3.0
Decrease in valuation allowance and other			89.3				4.7
Total effective income tax rate			-	%			-	%

 

The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities are presented below:

 

(in thousands)		As of December 31,
		2019				2018
Deferred tax assets:
Net operating loss carryforwards		$	6,232			$	7,573
Depletion carryforwards			2,569				2,166
Accrual and other			3,997				1,372
Stock-based compensation			469				445
Asset retirement obligations			4,659				4,567
Property and equipment			(2,253	)			(42	)
Total deferred tax assets			15,673				16,081
Deferred tax liabilities:
Interest in partnerships			(338	)			(512	)
ASC 842 Operating Leases			(12	)			-
Derivative and other			(1,689	)			(1,008	)
Less valuation allowance			(13,634	)			(14,561	)
Net deferred tax asset		$	-			$	-

 

 

The Company has net operating losses (“NOL”) of approximately $21.6 million available to reduce future years’ federal taxable income. The federal net operating losses expire beginning in 2031 through 2037, while the current 2018 and 2019 net operating losses will never expire. The Company has various state NOL carryforwards available to reduce future years' state taxable income, which are dependent on apportionment percentages and state laws that can change from year to year and impact the amount of such carryforwards. These state NOL will expire beginning in 2023 through 2039 depending upon each jurisdiction’s specific law surrounding NOL carryforwards. Tax returns are subject to audit by various taxation authorities. The results of any audits will be accounted for in the period in which they are determined

 

The Company believes that the tax positions taken in the Company’s tax returns satisfy the more likely than not threshold for benefit recognition. 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 recognize interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2019 and 2018, the Company did not have any uncertain tax positions.

 

Note 13 - 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 us. Unobservable inputs are inputs that reflect our 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. Our 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. We have consistently applied the valuation techniques discussed below for all periods presented.

 

The following table presents our financial assets and liabilities that were accounted for at fair value on a recurring basis by level within the fair value hierarchy:

 

		Fair Value Measurements Using
(in thousands)		Level 1				Level 2				Level 3				Total
December 31, 2019
Assets:
Commodity derivatives		$	-			$	7,079			$	-			$	7,079
Liabilities:
Commodity derivatives		$	-			$	556			$	-			$	556
December 31, 2018
Assets:
Commodity derivatives		$	-			$	7,022			$	-			$	7,022

 

 

Commodity Derivatives 

 

As of December 31, 2019, our commodity derivative financial instruments are comprised of natural gas and oil swaps and costless collars. 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. Our estimates of fair value of derivatives include consideration of the counterparty’s credit worthiness, our 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 significant inputs are observable, either directly or indirectly; therefore, our derivative instruments are included within the Level 2 fair value hierarchy.

 

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

 

Certain assets and liabilities are measured at fair value on a non-recurring basis. These assets and liabilities are not measured at fair value on an ongoing basis; however they are subject to fair value adjustments in certain circumstances. The fair value of the following assets and liabilities are based on unobservable pricing inputs and therefore, are included within the Level 3 fair value hierarchy.

 

Firm transportation contracts. We assume, at times, certain firm transportation contracts as part of our acquisitions of oil and natural gas properties. The fair value of the firm transportation contract obligations was determined based upon the contractual obligations assumed by us and discounted based upon our effective borrowing rate.

 

Debt Discount. The fair value of the debt discount from the 1,425 and 585 additional Class A Units issued in connection with the Subordinated Notes and 2018 Subordinated Notes was $1.3 million and $490,000, respectively. The debt discount was based on the relative fair value of Class A Units. Class A Units were issued contemporaneously at $1,000 per Class A Unit.

 

Asset Retirement Obligation. The fair value of our asset retirement obligation liability is recorded in the period in which it is incurred or assumed by taking into account the cost of abandoning oil and gas wells ranging from $20,000 to $45,000, which is based on our historical experience and industry expectations for similar work; the estimated timing of reclamation ranging from one to 75 years based on estimates from reserve engineers; an inflation rate between 1.52% to 2.79%; and a credit adjusted risk-free rate between 3.28% to 8.27%, which takes into account our credit risk and the time value of money. During the year ended December 31, 2019, we had minimal additions and approximately $290,000 of revisions to asset retirement obligations. During the year ended December 31, 2018, we recorded additions to asset retirement obligations of approximately $14.1 million, which was the result of the Carbon California, Seneca, Liberty, and OIE Membership Acquisitions.

 

Note 14 - Commodity Derivatives

 

We historically use commodity-based derivative contracts to manage exposures to commodity price on a portion of our oil and natural gas production. We do not hold or issue derivative financial instruments for speculative or trading purposes. We also have entered into, on occasion, oil and natural gas physical delivery contracts to effectively provide commodity price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. These contracts are not recorded at fair value in the consolidated financial statements.

 

 

We have entered into swap and costless collar derivative agreements to hedge a portion of our oil and natural gas production through 2022. As of December 31, 2019, these derivative agreements consisted of the following:

 

		Natural Gas Swaps								Natural Gas Collars
						Weighted Average								Weighted Average Price
Year		MMBtu				Price (a)				MMBtu				Range (a)
2020			12,433,000			$	2.73				3,430,000				$2.10 – $2.75
2021			6,448,000			$	2.58				1,745,000				$2.25 – $2.75

 

			Oil Swaps*																Oil Collars*
Year			WTI Bbl				Weighted Average Price (b)				Brent Bbl				Weighted Average Price (c)				WTI Bbl				Weighted Average Price (b)				Brent Bbl				Weighted Average Price (c)
2019			17,523				$53.30				13,805				$64.87				1,700				$47.50 - $57.35				4,500				$47.00 - $75.00
2020				121,147			$	55.37				207,182			$	64.62				28,200				$47.00 - $60.15				57,900			$47.00 - $75.00
2021				-			$	-				86,341			$	67.12				66,200				$47.00 - $60.15				190,000			$47.00 - $75.00
2022				-			$	-				-			$	-				-			$	-				199,900			$50.00 - $61.00

 

*	Includes 100% of Carbon California’s outstanding derivative hedges at December 31, 2019, and not our proportionate share.
(a)	NYMEX Henry Hub Natural Gas futures contracts for the respective period.
(b)	NYMEX Light Sweet Crude West Texas Intermediate futures contracts for the respective period.
(c)	Brent future contracts for the respective period.

  

For our swap instruments, we receive a fixed price for the hedged commodity and pay 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. Costless collars are designed to establish floor and ceiling prices on anticipated future oil and gas production. The ceiling establishes a maximum price that the Company will receive for the volumes under contract, while the floor establishes a minimum price.

 

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.

 

		As of December 31,
(in thousands)		2019				2018
Commodity derivative contracts:
Commodity derivative asset		$	5,915			$	3,517
Commodity derivative asset – non-current		$	1,164			$	3,505
Commodity derivative liability		$	469			$	-
Commodity derivative liability – non-current		$	87			$	-

 

The following table summarizes the commodity derivative gain presented in the accompanying consolidated statements of operations:

 

		Year Ended December 31,
(in thousands)		2019				2018
Commodity derivative contracts:
Settlement gain (loss)		$	3,543			$	(3,848	)
Unrealized (loss) gain			(499	)			8,742
Total commodity derivative gain		$	3,044			$	4,894

 

 

We net our derivative instrument fair value amounts pursuant to ISDA Master Agreements, which provide 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 effect of netting arrangements for recognized derivative assets and liabilities that are subject to master netting arrangements or similar arrangements in the consolidated balance sheet as of December 31, 2019:

 

										Net
		Gross								Recognized
		Recognized				Gross				Fair Value
		Assets/				Amounts				Assets/
Balance Sheet Classification (in thousands)		Liabilities				Offset				Liabilities
Commodity derivative assets:
Commodity derivative asset		$	6,917			$	(1,002	)		$	5,915
Commodity derivative asset – non-current			3,478				(2,314	)			1,164
Total derivative assets		$	10,395			$	(3,316	)		$	7,079
Commodity derivative liabilities:
Commodity derivative liability		$	(1,471	)		$	1,002			$	(469	)
Commodity derivative liability – non-current			(2,401	)			2,314				(87	)
Total derivative liabilities		$	(3,872	)		$	3,316			$	(556	)

 

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

 

Note 15 - Commitments and Contingencies

 

We have entered into firm transportation contracts to ensure the transport for certain of our gas production to purchasers. Firm transportation volumes and the related demand charges for the remaining term of these contracts as of December 31, 2019 are summarized in the table below.

 

Period		Dekatherms per day				Demand Charges
Jan 2020 – Mar 2020			58,871			$	0.20 - 0.62
Apr 2020 – May 2020			57,791			$	0.20 - 0.56
Jun 2020 – Oct 2020			56,641			$	0.20 - 0.56
Nov 2020 – Aug 2022			50,341			$	0.20 - 0.56
Sep 2022 – May 2027			30,990			$	0.20 - 0.21
Jun 2027 – May 2036			1,000			$	0.20

 

As of December 31, 2019, the remaining commitment related to the firm transportation contracts assumed in the EXCO Acquisition in October 2016 and the OIE Membership Acquisition is $14.6 million and reflected in the Company’s consolidated balance sheet. These contractual obligations are reduced monthly as the Company pays these firm transportation obligations.

 

Natural gas processing agreement

 

We have entered into an initial five-year gas processing agreement expiring in 2022. We have an option to extend the term of the agreement by another five years. The related demand charges for volume commitments over the remaining term of the agreement are approximately $1.8 million per year. We will pay a processing fee of $2.50 per Mcf for the term of the agreement, with a minimum annual volume commitment of 720,000 Mcf.

 

Capital Commitments

 

As of December 31, 2019, we had no capital commitments.

 

Note 16 - Supplemental Cash Flow Disclosure

 

Supplemental cash flow disclosures are presented below:

 

		Year Ended December 31,
(in thousands)		2019				2018
Cash paid during the period for:
Interest		$	9,191			$	4,217
Non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities		$	(2,563	)		$	(206	)
Adjustments to OIE Membership Acquisition purchase price		$	1,505				-

 

 

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

 

Estimated Proved Oil, Natural Gas, and Natural Gas Liquid Reserves

 

The reserve estimates as of December 31, 2019 and 2018 presented herein were made in accordance with oil and gas reserve estimation and disclosure authoritative accounting guidance.

 

Proved oil, natural gas, and natural gas liquid reserves as of December 31, 2019 and 2018 were calculated based on the prices for oil, natural gas, and natural gas liquids 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.

 

Our estimates of our net proved, net proved developed, and net proved undeveloped oil, gas and natural gas liquids reserves and changes in our net proved oil, natural gas, and natural gas liquid reserves for 2019 and 2018 are presented in the table below. Proved oil, natural gas, and natural gas liquid 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, 2019 and 2018 unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Prices do not include the effects of commodity derivatives. The independent 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, 2019 and 2018. 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 our 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, 2019 and 2018.

 

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 changes in quantities of proved oil, natural gas, and natural gas liquid reserves for the years ended December 31, 2019 and 2018 are as follows (in thousands):

 

		2019																2018
		Oil				Natural Gas				NGL				Total				Oil				Natural Gas				NGL				Total
		MBbls				MMcf				MBbls				MMcfe				MBbls				MMcf				MBbls				MMcfe
Proved reserves, beginning of year			18,898				455,400				1,923				580,326				919				81,702				-				87,216
Revisions of previous estimates			(1,362	)			24,194				(618	)			12,310				(2,803	)			1,832				(1,147	)			(21,868	)
Extensions and discoveries			826				1,187				77				6,605				-				-				-				-
Production			(589	)			(21,436	)			(36	)			(25,182	)			(451	)			(4,798	)			(33	)			(7,702	)
Purchases of reserves in-place			-				-				-				-				21,233				376,664				3,103				522,680
Sales of reserves in-place			(31	)			(8,980	)			-				(9,166	)			-				-				-				-
Proved reserves, end of year			17,742				450,365				1,346				564,893				18,898				455,400				1,923				580,326
Proved developed reserves at:
End of year			12,972				444,104				936				527,555				14,336				450,424				1,472				545,272
Proved undeveloped reserves at:
End of year			4,770				6,261				410				37,338				4,562				4,976				451				35,054

 

The estimated proved reserves for December 31, 2019 and 2018 includes approximately 3.4 Bcfe and 3.3 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:

 

(in thousands)		2019				2018
Oil and gas properties:
Proved oil and gas properties		$	351,488			$	347,059
Unproved properties			4,872				5,416
Accumulated depreciation, depletion, amortization and impairment			(109,344	)			(98,604	)
Total		$	247,016			$	253,871

 

 

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, 2019 and 2018:

 

(in thousands)		2019				2018
Property acquisition costs:
Unevaluated properties		$	-			$	3,464
Proved properties and gathering facilities			-				63,517
Development costs			7,676				2,074
Gathering facilities			-				460
Asset retirement obligations			-				14,085
Total		$	7,676			$	83,600

 

Our investment in unproved properties as of December 31, 2019, by the year in which such costs were incurred is set forth in the table below:

 

(in thousands)		2019				2018				2017 and Prior
Acquisition costs		$	496			$	3,464			$	912

 

Results of Operations from Oil and Gas Producing Activities

 

Results of operations from oil and gas producing activities for the years ended December 31, 2019 and 2018 are presented below:

 

(in thousands)		2019				2018
Revenues:
Oil, gas and NGL sales, including commodity derivative gains and losses		$	96,885			$	52,946
Expenses:
Production expenses			41,307				22,226
Depletion expense			14,062				7,305
Accretion of asset retirement obligations			1,625				868
Total expenses			56,994				30,399
Results of operations from oil and gas producing activities		$	39,891			$	22,547
Depletion rate per Mcfe		$	0.56			$	0.89

 

Standardized Measure of Discounted Future Net Cash Flows

 

Future oil and gas sales are calculated applying the prices used in estimating our 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 our proved reserves. Management does not rely upon the information that follows in making investment decisions.

 

		December 31,
(in thousands)		2019				2018
Future cash inflows		$	2,212,049			$	2,878,392
Future production costs			(1,306,608	)			(1,538,870	)
Future development costs			(77,952	)			(76,852	)
Future income taxes			(146,951	)			(258,277	)
Future net cash flows			680,538				1,004,393
10% annual discount			(408,690	)			(612,325	)
Standardized measure of discounted future net cash flows		$	271,848			$	392,068

 

 

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,
(in thousands)		2019				2018
Standardized measure of discounted future net cash flows, beginning of period		$	392,068			$	57,082
Sales of oil and gas, net of production costs and taxes			(49,746	)			(25,681	)
Price revisions			(158,799	)			133,789
Extensions, discoveries and improved recovery, less related costs			10,822				-
Changes in estimated future development costs			(3,041	)			(32,711	)
Development costs incurred during the period			6,685				926
Quantity revisions			5,565				(23,484	)
Accretion of discount			39,207				5,708
Net changes in future income taxes			39,929				(89,117	)
Purchases of reserves-in-place			-				391,877
Sales of reserves-in-place			(4,004	)			-
Changes in production rate timing and other			(6,838	)			(26,321	)
Standardized measure of discounted future net cash flows, end of period		$	271,848			$	392,068

 

The twelve-month weighted averaged adjusted prices in effect at December 31, 2019 and 2018 were as follows:

 

		2019				2018
Oil (per Bbl)		$	55.69			$	65.56
Natural Gas (per Mcf)		$	2.58			$	3.10

 

 

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 us and our consolidated subsidiaries is made known to the officers who certify our 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. Based on this evaluation, they believe that as of December 31, 2019, 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 is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and is accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

 

Management’s Annual Report on Internal Control Over Financial Reporting

 

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

 

As of December 31, 2019, management assessed the effectiveness of our 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. Because of its inherent limitations, internal control over financial reporting is not intended to provide absolute assurance that a misstatement of our financial statements would be prevented or detected. Based on this assessment, our management concluded that our internal control over financial reporting was effective as of December 31, 2019 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with GAAP.

 

This Annual Report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting due to permanent relief accorded to smaller reporting companies in the Dodd-Frank Act.

 

Changes in Internal Control Over Financial Reporting.

 

There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2019, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

Item 9B. Other Information.

 

None.

 

 

PART III

 

Item 10. Directors, Executive Officers and Corporate Governance

 

The information required by Item 10 is incorporated by reference to the information provided in the Company’s information statement for the 2020 annual meeting of stockholders to be filed within 120 days from December 31, 2019.

 

Item 11. Executive Compensation.

 

The information required by Item 11 is incorporated by reference to the information provided in the Company’s information statement for the 2020 annual meeting of stockholders to be filed within 120 days from December 31, 2019.

 

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

  

Additional information required by Item 12 is incorporated by reference to the information provided in the Company’s information statement for the 2020 annual meeting of stockholders to be filed within 120 days from December 31, 2019.

 

Equity Compensation Plans

 

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, 2019:

 

		Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a)				Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column(a)) (b)
Equity compensation plans approved by security holders			576,102				323,000
Equity compensation plans not approved by security holders			-				-

 

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

 

The information required by Item 13 is incorporated by reference to the information provided in the Company’s information statement for the 2020 annual meeting of stockholders to be filed within 120 days from December 31, 2019.

 

Item 14. Principal Accounting Fees and Services.

 

The information required by Item 14 is incorporated by reference to the information provided in the Company’s information statement for the 2020 annual meeting of stockholders to be filed within 120 days from December 31, 2019.

 

 

PART IV

 

Item 15. Exhibits, Financial Statement Schedules

 

(a)	The following documents are filed as part of this Annual Report on Form 10-K or are incorporated by reference:

 

	(1)	Financial Statements. See Item 8 of this Annual Report on Form 10-K.
	(2)	Financial Statement Schedules: All schedules have been omitted because the information is either not required or the required disclosures are contained in the consolidated 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, incorporated by reference to Exhibit 2.4 to Form 10-K filed on March 31, 2017.
2.5		Purchase and Sale Agreement, dated as of October 20, 2017, between Seneca Resources Corporation, as Seller, and Carbon California Company, LLC, as buyer, incorporated by reference to Exhibit 2.1 to Form 10-Q/A filed on June 19, 2018.
2.6		Amendment #1, dated December 15, 2017, to the Purchase and Sale Agreement, dated as of October 20, 2017, between Seneca Resources Corporation, as Seller, and Carbon California Company, LLC, as buyer, incorporated by reference to Exhibit 2.2 to Form 10-Q filed on May 15, 2018.
2.7		Amendment #2, dated January 10, 2018, to the Purchase and Sale Agreement, dated as of October 20, 2017, between Seneca Resources Corporation, as Seller, and Carbon California Company, LLC, as buyer, incorporated by reference to Exhibit 2.3 to Form 10-Q/A filed on June 19, 2018.
2.8		Amendment #3 dated January 31, 2018, to the Purchase and Sale Agreement, dated as of October 20, 2017, between Seneca Resources Corporation, as Seller, and Carbon California Company, LLC, as buyer, incorporated by reference to Exhibit 2.4 to Form 10-Q/A filed on June 19, 2018.
3.1		Amended and Restated Certificate of Incorporation of Carbon Natural Gas Company, dated as of April 27, 2011, incorporated by reference to Exhibit 3(i)(a) to Form 10-K filed on March 31, 2017.
3.2		Certificate of Amendment to the Certificate of Incorporation of Carbon Natural Gas Company, dated as of July 14, 2011, incorporated by reference to Exhibit 3(i) to Form 8-K filed on July 19, 2011.

 

 

3.3		Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Carbon Natural Gas Company, dated as of March 15, 2017, incorporated by reference to Exhibit 3.1 to Form 8-K filed on March 16, 2017.
3.4		Certificate of Correction to the Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Carbon Natural Gas Company, dated as of March 23, 2018, incorporated by reference to Exhibit 3.1 to Form 8-K/A filed on March 28, 2018.
3.5		Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Carbon Natural Gas Company, effective June 1, 2018, incorporated by reference to Exhibit 3(i) to Form 8-K filed on June 4, 2018.
3.6		Amended and Restated Bylaws, incorporated by reference to Exhibit 3(i) to Form 8-K filed on May 5, 2015.
3.7		Amendment No. 1 to Amended and Restated Bylaws, incorporated by reference to Exhibit 3(ii) to Form 8-K filed on June 4, 2018.
3.8		Certificate of Designation with respect to Series B Convertible Preferred Stock, dated as of April 5, 2018, incorporated by reference to Exhibit 3(i) to Form 8-K filed on April 9, 2018.
4.1		Description of Securities.
10.1		Credit Agreement, by and between the Company, Nytis Exploration Company LLC, Nytis Exploration (USA) Inc. and LegacyTexas Bank, dated October 3, 2016, incorporated by reference to Exhibit 10.1 to Form 10-K filed on March 31, 2017.
10.2		Unconditional Guaranty from Nytis Exploration Company, LLC and Nytis Exploration Company (USA) Inc. to LegacyTexas Bank, dated October 3, 2016, incorporated by reference to Exhibit 10.1(a) to Form 10-K filed on March 31, 2017.
10.3		Security Agreement from Carbon Natural Gas Company, Nytis Exploration Company LLC and Nytis Exploration Company (USA) Inc. to LegacyTexas Bank, dated October 3, 2016, incorporated by reference to Exhibit 10.1(b) to Form 10-K filed on March 31, 2017.
10.4		Third Amendment to Credit Agreement, among Carbon Natural Gas Company and LegacyTexas Bank, dated March 27, 2018, incorporated by reference to Exhibit 10.4 to Form 10-K filed on April 2, 2018.
10.5		Amended and Restated Credit Agreement, among Carbon Appalachia Enterprises, LLC and Nytis Exploration (USA) Inc. and LegacyTexas Bank, dated December 31, 2018, incorporated by reference to Exhibit 10.2 to Form 8-K filed on January 7, 2019.
10.6		Purchase Agreement by and among the Company and Yorktown Energy Partners XI, LP, dated April 6, 2018, incorporated by reference to Exhibit 10.1 to Form 8-K filed on April 9, 2018.
10.7		Membership Interest Purchase Agreement, dated as of May 4, 2018, by and among Old Ironsides Fund II-A Portfolio Holding Company, LLC, Old Ironsides Fund II-B Portfolio Holding Company, LLC, and Carbon Natural Gas Company, incorporated by reference to Exhibit 10.1 to Form 10-Q filed on August 14, 2018.
10.8		Letter Amendment, dated July 20, 2018, to Membership Interest Purchase Agreement, dated as of May 4, 2018, by and among Old Ironsides Fund II-A Portfolio Holding Company, LLC, Old Ironsides Fund II-B Portfolio Holding Company, LLC, and Carbon Natural Gas Company, incorporated by reference to Form 10-Q filed on August 14, 2018.
10.9		Letter Amendment, dated October 15, 2018, to Membership Interest Purchase Agreement, dated as of May 4, 2018, by and among Old Ironsides Fund II-A Portfolio Holding Company, LLC, Old Ironsides Fund II-B Portfolio Holding Company, LLC, and Carbon Energy Corporation, incorporated by reference to Exhibit 10.1 to Form 8-K filed on October 19, 2018.
10.10		Letter Amendment, dated November 6, 2018, to Membership Interest Purchase Agreement, dated as of May 4, 2018, by and among Old Ironsides Fund II-A Portfolio Holding Company, LLC, Old Ironsides Fund II-B Portfolio Holding Company, LLC, and Carbon Energy Corporation, incorporated by reference to Exhibit 10.1 to Form 8-K filed on November 13, 2018.
10.11		Letter Amendment, dated November 30, 2018, to Membership Interest Purchase Agreement, dated as of May 4, 2018, by and among Old Ironsides Fund II-A Portfolio Holding Company, LLC, Old Ironsides Fund II-B Portfolio Holding Company, LLC, and Carbon Energy Corporation, incorporated by reference to Exhibit 10.1 to Form 8-K filed on December 11, 2018.
10.12		Letter Amendment, dated December 31, 2018, to Membership Interest Purchase Agreement, dated as of May 4, 2018, by and among Old Ironsides Fund II-A Portfolio Holding Company, LLC, Old Ironsides Fund II-B Portfolio Holding Company, LLC, and Carbon Energy Corporation, incorporated by reference to Exhibit 10.1 to Form 8-K filed on January 7, 2019.

 

 

10.13		Employment Agreement between the Company and Patrick McDonald, incorporated by reference to Exhibit 10.2 to Form 8-K filed on April 5, 2013.
10.14		Employment Agreement between the Company and Mark Pierce, incorporated by reference to Exhibit 10.3 to Form 8-K filed on April 5, 2013.
10.15		Employment Agreement between the Company and Kevin Struzeski, incorporated by reference to Exhibit 10.4 to Form 8-K filed on April 5, 2013.
10.16		Amendment to the Employment Agreement of Patrick R. McDonald, dated March 4, 2019, incorporated by reference to Exhibit 10.1 to Form 8-K filed on March 6, 2019.
10.17		Amendment to the Employment Agreement of Mark D. Pierce, dated March 4, 2019, incorporated by reference to Exhibit 10.2 to Form 8-K filed on March 6, 2019.
10.18		Amendment to the Employment Agreement of Kevin D. Struzeski, dated March 4, 2019, incorporated by reference to Exhibit 10.3 to Form 8-K filed on March 6, 2019.
10.19		Carbon Natural Gas Company 2015 Annual Incentive Plan, incorporated by reference to Exhibit 10.2 to Form 10-Q filed on May 14, 2015.
10.20		Carbon Natural Gas Company 2015 Stock Incentive Plan incorporated by reference to Exhibit 10.12 to Form 10-K filed on March 28, 2016.
10.21		Carbon Natural Gas Company 2016 Annual Incentive Plan, incorporated by reference to Exhibit 10.1 to Form 10-Q filed on May 23, 2016.
10.22		Carbon Natural Gas Company 2017 Annual Incentive Plan, incorporated by reference to Exhibit 10.3 to Form 10-Q filed on May 19, 2017.
10.23		Carbon Energy Corporation 2019 Long Term Incentive Plan, incorporated by reference to Appendix A to the definitive proxy statement filed on April 23, 2019.
10.24		Second Amendment to the Amended and Restated Credit Agreement, dated August 14, 2019,  incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 15, 2019.
10.25		Omnibus Annual Incentive Plan, dated August 9, 2019, incorporated by reference to Exhibit 10.2 to Form 10-Q filed on November 13, 2019.
10.26*		Third Amendment to the Amended and Restated Credit Agreement, dated February 14, 2020.
16.1		Copy of EKS&H Letter to the Securities and Exchange Commission, dated October 4, 2018, incorporated by reference to Exhibit 16.1 to Form 8-K filed on October 4, 2018.
21.1*		Subsidiaries of the Company.
23.1*		Consent of Plante & Moran, PLLC 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.
99.2*		Report of Cawley, Gillespie & Associates, Inc., Independent Petroleum Engineers.
99.3*		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.

 

Item 16. Form 10-K Summary

 

None.

 

 

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 30, 2020	CARBON ENERGY CORPORATION (Registrant)
	By:	/s/ Patrick R. McDonald
		Patrick R. McDonald
		Chief Executive 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 and in the capacities and on the dates indicated.

 

Signatures		Title		Date
/s/ Patrick R. McDonald		Director and Chief Executive Officer		March 30, 2020
Patrick R. McDonald		(Principal Executive Officer)
/s/ Kevin D. Struzeski		Chief Financial Officer, Treasurer and Secretary		March 30, 2020
Kevin D. Struzeski		(Principal Financial Officer and Principal Accounting Officer)
/s/ James H. Brandi		Chairman and Director		March 30, 2020
James H. Brandi
/s/ Peter A. Leidel		Director		March 30, 2020
Peter A. Leidel
/s/ John A. Bailey		Director		March 30, 2020
John A. Bailey
/s/ Edwin H. Morgens		Director		March 30, 2020
Edwin H. Morgens
/s/ David H. Kennedy		Director		March 30, 2020
David H. Kennedy

 

97