Carbon Energy (CRBO) Risk Analysis

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.

Our future financial condition and results of operations will depend on the success of our acquisition, exploration, development and production activities. These activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production. Our decision to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see "Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our proved reserves." The costs of exploration, exploitation, and development activities are subject to numerous uncertainties beyond our control and increases in those costs can adversely affect the economics of a project. In addition, drilling and completion costs may increase prior to completion of any particular project. Many factors may curtail, delay or cancel scheduled drilling and production projects, including: - high costs, shortages or delivery delays of drilling rigs, equipment, labor or other services;- unexpected operational events and drilling conditions;- sustained depressed oil and natural gas prices and further reductions in oil and natural gas prices;- limitations in the market for oil and natural gas;- problems in the delivery of oil and natural gas to market (see "Our business depends in part on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities would interfere with our ability to market the natural gas we produce.");- adverse weather conditions;- facility or equipment malfunctions;- equipment failures or accidents;- title problems;- pipe or cement failures;- casing collapses;- compliance with environmental and other governmental requirements;- delays in obtaining, extending or renewing necessary permits or the inability to obtain, extend or renew such permits at all;- environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;- lost or damaged oilfield drilling and service tools;- unusual or unexpected geological formations;- loss of drilling fluid circulation;- pressure or irregularities in formations;- fires, blowouts, surface craterings and explosions; and - uncontrollable flows of oil, natural gas or well fluids. Additionally, drilling, transportation and processing of hydrocarbons bear an inherent risk of loss of containment. Potential consequences include loss of reserves, loss of production, loss of economic value associated with an affected wellbore, contamination of soil, ground water, and surface water, as well as potential fines, penalties, or damages associated with any of the foregoing consequences.

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.

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.

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.

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.

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 be subject to regulation that restricts our ability to discharge water produced as part of our natural gas production operations. Productive zones frequently contain water that must be removed for the oil and natural gas to produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether we can produce natural gas in commercial quantities. The produced water must be transported from the production site and injected into disposal wells. The capacity of the disposal wells we own may not be sufficient to receive all the water produced from our wells and may affect our ability to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability. Where water produced from our projects fails to meet the quality requirements of applicable regulatory agencies, our wells produce water in excess of the applicable volumetric permit limits, the disposal wells fail to meet the requirements of all applicable regulatory agencies, or we are unable to secure access to disposal wells with sufficient capacity to accept all of the produced water, we may be required to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur: - we cannot obtain future permits from applicable regulatory agencies;- water of lesser quality or requiring additional treatment is produced;- our wells produce excess water;- new laws and regulations require water to be disposed in a different manner; or - costs to transport the produced water to the disposal wells increase.

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.

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.

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.

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.

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.

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.

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.

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.