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;
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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;
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The
Safe Drinking Water Act (“SDWA”), which governs the disposal of wastewater in underground injection
wells; and
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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.
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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:
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domestic
and foreign supply of and demand for oil, natural gas and NGLs;
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market
prices of oil, natural gas and NGLs;
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level
of consumer product demand;
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overall
domestic and global political and economic conditions;
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political
and economic conditions in producing countries, including those in the Middle East, Russia, South America and Africa;
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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;
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actions
of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production
controls;
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impact
of the U.S. dollar exchange rates on commodity prices;
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technological
advances affecting energy consumption and energy supply;
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domestic
and foreign governmental regulations and taxation;
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impact
of energy conservation efforts;
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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;
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the ability to export
liquid natural gas outside of the United States; and
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price
and availability of alternative fuels.
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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:
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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;
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the
amount of cash flow available for capital expenditures;
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our
ability to replace our production and future rate of growth;
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our
ability to borrow money or raise additional capital and our cost of such capital; and
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our
ability to meet our financial obligations.
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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:
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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;
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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;
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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;
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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;
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Certain
of our assets are operated by entities that we do not control; and
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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.
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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:
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a
significant portion of our cash flows could be used to service our indebtedness;
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a
high level of debt would increase our vulnerability to general adverse economic and industry conditions;
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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;
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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;
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our
debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;
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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
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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.
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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:
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reducing
or delaying capital expenditures;
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seeking
additional debt financing or equity capital;
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restructuring
or refinancing debt.
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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:
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incur
additional liens;
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sell,
transfer or dispose of assets;
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merge
or consolidate, wind-up, dissolve or liquidate;
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make
dividends and distributions on, or repurchases of, equity;
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make
certain investments;
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enter
into certain transactions with our affiliates;
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enter
into sales-leaseback transactions;
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make
optional or voluntary payment of debt;
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change
the nature of our business;
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change
our fiscal year to make changes to accounting treatments or reporting practices;
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amend
constituent documents; or
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enter
into certain hedging transactions.
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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:
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the
actual prices we receive for oil and natural gas;
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our
actual operating costs in producing oil and natural gas;
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the
amount and timing of actual production;
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the
amount and timing of our capital expenditures;
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supply
of and demand for oil and natural gas; and
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changes
in governmental regulations or taxation.
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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:
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the
volume of hydrocarbons we are able to produce from existing wells;
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the
prices at which our production is sold;
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the
levels of our operating expenses; and
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our
ability to acquire, locate, and produce new reserves.
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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:
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high
costs, shortages or delivery delays of drilling rigs, equipment, labor or other services;
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unexpected
operational events and drilling conditions;
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sustained
depressed oil and natural gas prices and further reductions in oil and natural gas prices;
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limitations
in the market for oil and natural gas;
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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.”);
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adverse
weather conditions;
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facility
or equipment malfunctions;
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equipment
failures or accidents;
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pipe
or cement failures;
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compliance
with environmental and other governmental requirements;
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delays
in obtaining, extending or renewing necessary permits or the inability to obtain, extend or renew such permits at all;
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environmental
hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;
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lost
or damaged oilfield drilling and service tools;
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unusual
or unexpected geological formations;
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loss
of drilling fluid circulation;
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pressure
or irregularities in formations;
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fires,
blowouts, surface craterings and explosions; and
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uncontrollable
flows of oil, natural gas or well fluids.
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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:
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we
cannot obtain future permits from applicable regulatory agencies;
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water
of lesser quality or requiring additional treatment is produced;
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our
wells produce excess water;
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new
laws and regulations require water to be disposed in a different manner; or
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costs
to transport the produced water to the disposal wells increase.
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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:
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the
validity of our assumptions about estimated proved reserves, future production, commodity prices, revenues, capital expenditures,
operating expenses, and costs;
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an
inability to obtain satisfactory title to the assets we acquire;
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a
decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;
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a
significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
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the
assumption of unknown liabilities, losses, or costs for which we obtain no or limited indemnity or other recourse;
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the
diversion of management’s attention from other business concerns;
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an
inability to hire, train, or retain qualified personnel to manage and operate our growing assets; and
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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.
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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:
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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;
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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;
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data
corruption or operational disruption of production infrastructure, which could result in loss of production, accidental discharge
and other operational incidents;
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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;
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a
cybersecurity attack on a vendor or service provider, which could result in supply chain disruptions and could delay or halt
operations;
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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;
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a
cybersecurity attack on our automated and surveillance systems could cause a loss in production, potential environmental hazards
and other operational problems; and
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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.
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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.