We make available free of charge on our website (www.callon.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the SEC. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers, like Callon, that file electronically with the SEC.
ItemITEM 1A. Risk Factors
Risk Factors
Risks Related to the Oil & Natural Gas Industry
Oil and natural gas prices are volatile, and substantial or extended declines in prices may adversely affect our results of operations and financial condition.condition. Our success is highly dependent on prices for oil and natural gas, which have been extremely volatile in recent years. Approximately 77% of our anticipated 2018 production, on a BOE basis, is oil. Starting inyears been, and we expect will continue to be, extremely volatile. During the second half of 2014, thefive years ended December 31, 2021, NYMEX price for a barrel of oil fell sharply, from a price of $105.37 on June 30, 2014 to $26.21 on February 11, 2016. During 2017, NYMEXWTI prices ranged from a high of $85.64 per barrel on October 26, 2021 to a low of $42.53-$36.98 per Bblbarrel on June 21, 2017 toApril 20, 2020, and NYMEX Henry Hub prices ranged from a high of $60.42$23.86 per BblMMBtu on December 29, 2017. In addition, NYMEX prices forFebruary 17, 2021 to a low of $1.33 per MMBtu on September 21, 2020. Prices were particularly volatile in 2020 and 2021, with five-year highs occurring in 2021 and five-year lows occurring in 2020, as a result of multiple significant factors impacting supply and demand in the global oil and natural gas have been low compared with historical prices. Extended periods of low prices for oil or natural gas will have a material adverse effect on us.markets, including those relating to the COVID-19 global pandemic. The prices of oil and natural gas depend on factors we cannot control, such as macro economicmacro-economic conditions, levels of production, domestic and worldwide inventories, demand for oil and natural gas, the capacity of U.S. and international refiners to use U.S. supplies of oil, natural gas and NGLs, relative price and availability of alternative forms of energy, actions by non-governmental organizations, OPEC and other countries, legislative and regulatory actions, technology developments impacting energy consumption and energy supply, and weather. PricesThese factors make it extremely difficult to predict future oil, natural gas and NGLs price movements with any certainty. We make price assumptions that are used for planning purposes, and a significant portion of our cash outlays, including rent, salaries and non-cancelable capital commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations on which these commitments were based, our financial results are likely to be adversely and disproportionately affected because these cash outlays are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices.
In general, prices of oil, and natural gas, willand NGLs affect the following aspects of our business:
our revenues, cash flows, earnings and returns;
the amount of oil and natural gas that we are economically able to produce;
our ability to attract capital to finance our operations and the cost of the capital;
the amount we are allowed to borrow under our Credit Facility;
the profit or loss we incur in exploring for and developing our reserves; and
the value of our oil and natural gas properties.
AnyA substantial andor extended decline in commodity prices may also reduce the priceamount of oil orand natural gas that we can produce economically and cause a significant portion of our development projects to become uneconomic. This may result in our having to make significant downward adjustments to our estimated proved reserves. A reduction in production could have an adverse effect on our borrowing capacity,also result in a shortfall in expected cash flows and require us to reduce capital spending, which could negatively affect our ability to obtain additional capital,replace our production and our revenues, profitabilityfuture rate of growth, or require us to borrow funds to cover any such shortfall, which we may be unable to obtain at such time on satisfactory terms. Additionally, a sustained period of weakness in oil, natural gas and cash flows.NGLs prices, and the resultant effects of such prices on our drilling economics and ability to raise capital, would require us to reevaluate and postpone or eliminate additional drilling.
Additionally, as of December 31, 2021, approximately 26% of our total net acreage was not held by production, and we had undeveloped leases representing 20% and 1% of our total net acreage scheduled to expire during 2022 and 2023, respectively, in each case assuming no exercise of lease extension options where applicable. The net acreage scheduled to expire in 2022 is substantially comprised of non-core acreage principally located in Texas. If we are required to further curtail our drilling program, we may be unable to continue to hold such leases that are scheduled to expire, which may further reduce our reserves. As a result, if oil, natural gas and/or NGL prices experience a sustained period of weakness, our future business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures may be materially and adversely affected.
If oil and natural gas prices remain depressed for extended periods of time, we may be required to make significant downward adjustments to the carrying value of our oil and natural gas properties. Under the full cost method, which we use to account for our oil and natural gas properties, the net capitalized costs of our oil and natural gas properties may not exceed the present value, discounted at 10%,PV-10 of future net cash flows fromour estimated net proved reserves, using the preceding 12-months’ average oil and natural gas prices,12-Month Average Realized Prices, plus the lower of cost or fair market value of our unproved properties. If such net capitalized costs of our oil and natural gas properties exceed this “ceiling test” limit, we must charge the amount of the excess to earnings. This type of charge will not affect our cash flows, but will reduce the book value of our stockholders’ equity. We review the carrying value of our properties quarterly and once incurred, a write-downan impairment of evaluated oil and natural gas properties is not reversible at a later date, even if prices increase. See “Note 2 - Summary of Significant Accounting Policies” of the Notes 2to our Consolidated Financial Statements as well as the Supplemental Information on Oil and 13Natural Gas Operations for additional information.
A negative shift in investor sentiment of the oil and gas industry could adversely affect our ability to raise debt and equity capital. Certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the Footnotessector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment advisors and certain sovereign wealth funds, pension funds, university endowments and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas production and related infrastructure projects. Such developments, including environmental, social and governance (“ESG”) activism
and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for potential development projects, impacting our future financial results.
We face various risks associated with increased activism against oil and natural gas exploration and development activities. Opposition toward oil and natural gas drilling and development activity has been growing globally and is particularly pronounced in the United States. Companies in the oil and natural gas industry are often the target of activist efforts from both individuals and non- governmental organizations regarding safety, human rights, climate change, environmental matters, sustainability, and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain operations such as drilling and development. Activism could materially and adversely impact our ability to operate our business and raise capital.
The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could materially and adversely affect our operations and profitability. From time to time, during periods of increasing oil and natural gas prices and in periods in which the levels of exploration and production increase, our industry experiences a shortage of drilling and workover rigs, other equipment, pipes, materials and supplies, water and qualified personnel. As a result of such shortage, the costs and delivery times of rigs, equipment and supplies often increase substantially, as well as the wages and costs of drilling rig crews and other experienced personnel and oilfield services, while the quality of these services and equipment may suffer. This impact may be magnified to the Financial Statements for additional information.extent that the Company's ability to participate in the commodity price increases is limited by its derivative risk management activities. Cost increases in and shortages of such resources may also result from a variety of other factors beyond our control, such as general inflationary pressures, transportation constraints, and increases in the cost of necessary inputs such as electricity, steel and other raw materials, including as a result of increased tariffs or geopolitical issues.
For the period ended December 31, 2017, we did not recognize a write-downAn excess supply of oil and natural gas propertiesmay in the future cause us to reduce production and shut-in our wells, any of which could adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures. An excess supply of oil and natural gas may result in transportation and storage capacity constraints. If, in the future, our transportation or storage arrangements become constrained or unavailable, we may incur significant operational costs if there is an increase in price for services or we may be required to shut-in or curtail production or flare our natural gas. If we were required to shut-in wells, we might also be obligated to pay certain demand charges for gathering and processing services and firm transportation charges for pipeline capacity we have reserved. Further, any prolonged shut-in of our wells may result in materially decreased well productivity once we are able to resume operations, and any cessation of drilling and development of our acreage could result in the expiration, in whole or in part, of our leases. All of these impacts may adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures.
Risks Related to the COVID-19 Pandemic
The COVID-19 pandemic, and various governmental actions taken to mitigate its impact, materially adversely affected, and any future outbreak of any other highly infectious or contagious diseases may materially adversely affect, our business, financial position, results of operations, and cash flows. The COVID-19 pandemic, and various governmental actions taken to mitigate its impact, have negatively impacted the global economy, disrupted global supply chains, and created significant volatility and disruption of financial and commodity markets, as well as resulted in an unprecedented decline in demand for oil and natural gas during 2020, which materially adversely affected our business, financial position, results of operations, and cash flows and exacerbated the potential negative impact from many of the other risks described herein, including those relating to our financial position and debt obligations. The pandemic has also increased volatility and, from time to time, caused negative pressure in the capital markets; as a result, in the future, we may experience difficulty accessing the capital or financing needed to fund our operations, which have substantial capital requirements, on satisfactory terms or at all, compounding liquidity risks associated with a material reduction in our revenues and cash flows as a result of any future declines in demand due to the ceiling test limitation. The ceiling test calculation asCOVID-19 pandemic or any future pandemic.
We expect the COVID-19 pandemic and related economic repercussions to continue to affect our business, financial condition, results of December 31, 2017 was calculated usingoperations, and cash flows. However, the average annual realized prices usedextent of the impact of the COVID-19 pandemic on our business and our operational and financial performance, including our ability to execute our business strategies and initiatives in determining the estimated future net cash flows from proved reservesexpected time frame, is uncertain and depends on various factors that we cannot predict, including the following: the severity and duration of $51.34 per barrelthe pandemic; governmental, business and other actions in response to the pandemic; the impact of the pandemic on economic activity; the response of the overall economy and the financial markets; the demand for oil and $2.98 per Mcf of natural gas. Oil prices continuegas, which may be reduced on a prolonged or permanent basis due to fluctuate and we may experience ceiling test write-downsa structural shift in the future. Any future ceiling test cushion,global economy in the way people work, travel, and interact, or in connection with a global recession or depression; any impairment in the risk we may incur write-downsvalue of our tangible or impairments, willintangible assets which could be subject to fluctuationrecorded as a result of acquisitiona weaker economic conditions or divestiture activity. commodity prices; and the potential effects on our internal controls, including those over financial reporting, as a result of changes in working environments, such as shelter-in-place and similar orders that are applicable to our
employees and business partners, among others. The challenges to working caused by the COVID-19 pandemic and related restrictions may have an impact on our employees’ wellness, which could impact employee retention, productivity and our culture. In addition, we may experience employee turnover as seen with companies throughout the U.S. economy. There are no comparable recent events that provide guidance as to the effect the COVID-19 pandemic may have, and as a result, the ultimate impact of the pandemic is highly uncertain and subject to change.
Operational Risks
Our operations are subject to operating hazards inherent to our industry that may adversely impact our ability to conduct business, and we may not be fully insured against all such operating risks. The operating hazards in exploring for and producing oil and natural gas include: encountering unexpected subsurface conditions that cause damage to equipment or personal injury, including loss of life; equipment failures that curtail or stop production or cause severe damage to or destruction of property, natural resources or other equipment; blowouts or other damages to the productive formations of our reserves that require a well to be re-drilled or other corrective action to be taken; and storms and other extreme weather conditions that cause damages to our production facilities or wells. Because of these or other events, we could experience environmental hazards, including release of oil and natural gas from spills, natural gas leaks, accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or fracturing fluids, including chemical additives, underground migration, and ruptures. If we experience any of these problems, we could incur substantial losses in excess of our insurance coverage.
The occurrence of a significant event or claim, not fully insured or indemnified against, could have a material adverse effect on our financial condition and operations. In accordance with industry practice, we maintain insurance against some of the operating risks to which our business is exposed. Also, no assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable to cover our possible losses from operating hazards and we may elect no or minimal insurance coverage.
Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns. Exploration, development, drilling and production activities are subject to many risks. We may invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that any leasehold acreage acquired will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, including wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, we may not be successful in controlling our drilling and production costs to improve our overall return and wells that are profitable may not achieve our targeted rate of return. Wells may have production decline rates that are greater than anticipated. Future drilling and completion efforts may impact production from existing wells, and parent-child effects may impact future well productivity as a result of timing, spacing proximity or other factors. Failure to conduct our oil and gas operations in a profitable manner may result in write- downs of our proved reserves quantities, impairment of our oil and gas properties, and a write-down in the carrying value of our unproved properties, and over time may adversely affect our growth, revenues and cash flows.
Multi-well pad drilling may result in volatility in our operating results. We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production. In addition, problems affecting a single well could adversely affect production from all of the wells on the pad, which would further cause delays in the scheduled commencement of production or interruptions in ongoing production. These delays or interruptions may cause volatility in our operating results. Further, any delay, reduction or curtailment of our development and producing operations due to operational delays caused by multi-well pad drilling could result in the loss of acreage through lease expirations.
Restrictions on our ability to obtain, recycle and dispose of water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner. Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local land owners and other third party sources for use in our operations. If drought conditions were to occur or demand for water were to outpace supply, our ability to obtain water could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. Along with the risks of other extreme weather events, drought risk, in particular, is likely increased by climate change. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows. In addition, significant amounts of water are produced in our operations. Inadequate access to or availability of water recycling or water disposal facilities could adversely affect our production volumes or significantly increase the cost of our operations.
Risks Related to Marketing and Transportation
Factors beyond our control, including the availability and capacity of gas processing facilities and pipelines and other transportation operations owned and operated by third parties, affect the marketability of our production. The ability to market oil and natural gas from our wells depends upon numerous factors beyond our control. A significant factor in our ability to market our production is the availability and capacity of gas processing facilities and pipeline and other transportation operations,
including trucking services, owned and operated by third parties. These facilities and services may be temporarily unavailable to us due to market conditions, physical or mechanical disruption, weather, lack of contracted capacity, available manpower, pipeline safety issues, or other reasons. In certain newer development areas, processing and transportation facilities and services may not be sufficient to accommodate potential production and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built. In addition, we or parties that we utilize might not be able to connect new wells that we complete to pipelines. Our failure to obtain access to processing and transportation facilities and services in a timely manner and on acceptable terms could materially harm our business. We may be required to shut in wells for lack of a market or because of inadequate or unavailable processing or transportation capacity. If that were to occur, we would be unable to realize revenue from those wells until transportation arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells, we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. If we were required to shut in our production for long periods of time due to lack of transportation capacity, it would have a material adverse effect on our business, financial condition, results of operations and cash flows.
Other factors that affect our ability to market our production include:
•the extent of domestic production and imports/exports of oil and natural gas;
•federal regulations authorizing exports of LNG, the development of new LNG export facilities under construction in the U.S. Gulf Coast region, and the first LNG exports from such facilities;
•the construction of new pipelines capable of exporting U.S. natural gas to Mexico and transporting Eagle Ford and Permian oil production to the Gulf Coast;
•the proximity of hydrocarbon production to pipelines;
•the demand for oil and natural gas by utilities and other end users;
•the availability of alternative fuel sources;
•the effects of inclement weather; and
•state and federal regulation of oil, natural gas and NGL marketing and transportation.
We have entered into firm transportation contracts that require us to pay fixed sums of money regardless of quantities actually shipped. If we are unable to deliver the minimum quantities of production, such requirements could adversely affect our results of operations, financial position, and liquidity. We have entered into firm transportation agreements for a portion of our production in certain areas in order to improve our ability, and that of our purchasers, to successfully market our production. We may also enter into firm transportation arrangements for additional production in the future. These firm transportation agreements may be more costly than interruptible or short-term transportation agreements. Additionally, these agreements obligate us to pay fees on minimum volumes regardless of actual throughput. If we have insufficient production to meet the minimum volumes, the requirements to pay for quantities not delivered could have an impact on our results of operations, financial position, and liquidity.
Risks Related to Our Reserves and Drilling Locations
Our estimated reserves are based on interpretations and assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. This 2021 Annual Report on Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This processcomplex and requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise.
These assumptions include those required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from the estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report.2021 Annual Report on Form 10-K. Additionally, estimates of reserves and future cash flows may be subject to material downward or upward revisions, based on production history, development drilling and exploration activities and prices of oil and natural gas.
You should not assume that any present valuePV-10 of future net cash flows from our estimated net proved reserves contained in this 2021 Annual Report on Form 10-K represents the market value of our oil and natural gas reserves. We base the estimated discounted future net cash flowsPV-10 from our estimated proved reserves at December 31, 20172021 on average 12-month pricesthe 12-Month Average Realized Prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production, and changes in governmental regulations or taxes. At December 31, 2017, approximately 35% of the discounted present value of our estimated net proved reserves consisted of PUDs. PUDs represented 49% of total proved reserves by volume. Recovery of PUDs generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumption that we will make significant capital expenditures to develop these PUDs and the actual costs, development schedule, and results associated with these properties may not be as estimated. In addition, the 10% discount factor that we useused to calculate the net present value of future net revenues and cash flowsPV-10 may not necessarily be the most appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil and gas industry in general.industry.
Unless we replace our oil and gas reserves, our reserves and production will decline.Our future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our production, revenues, reserve quantities and cash flows will decline. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. We may not be successful in finding, developing or acquiring additional reserves, and our efforts may not be economic. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be limited to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable.
Competitive industry conditions may negatively affect our ability to conduct operations. We compete with numerous other companies in virtually all facets of our business. Our competitors in development, exploration, acquisitions and production include major integrated oil and gas companies and smaller independents as well as numerous financial buyers, including many that have significantly greater resources than us. Therefore, competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit. We also compete for the materials, equipment, personnel and services that are necessary for the exploration, development and operation of our properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development. Factors that affect our ability to compete in the marketplace include:
our access to the capital necessary to drill wells and acquire properties;
our ability to acquire and analyze seismic, geological and other information relating to a property;
our ability to retain the personnel necessary to properly evaluate seismic and other information relating to a property;
our ability to procure materials, equipment, personnel and services required to explore, develop and operate our properties, including the ability to procure fracture stimulation services on wells drilled; and
our ability to access pipelines, and the location of facilities used to produce and transport oil and natural gas production.
The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget. From time to time, our industry experiences a shortage of drilling rigs, equipment, supplies, water or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews and other experienced personnel rise as the level of activity increases. Increasing levels of exploration and production may increase the demand for oilfield services and equipment, and the costs of these services and equipment may increase, while the quality of these services and equipment may suffer. The unavailability or high cost of drilling rigs, pressure pumping equipment, supplies, water or qualified personnel can materially and adversely affect our operations and profitability.
Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area. All of our producing properties are geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.
We maybe unable to integrate successfully the operations of recent and future acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisitions. Our business has and may in the future include producing property acquisitions that include undeveloped acreage. We can offer no assurance that we will achieve the desired profitability from our recent acquisitions or from any acquisitions we may complete in the future. In addition, failure to assimilate recent and future acquisitions successfully could adversely affect our financial condition and results of operations. Our acquisitions may involve numerous risks, including:
operating a larger combined organization and adding operations;
difficulties in the assimilation of the assets and operations of the acquired business, especially if the assets acquired are in a new geographic area;
risk that oil and natural gas reserves acquired may not be of the anticipated magnitude or may not be developed as anticipated;
loss of significant key employees from the acquired business;
inability to obtain satisfactory title to the assets we acquire;
a decrease in our liquidity if we use a portion of our available cash to finance acquisitions;
a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
diversion of management’s attention from other business concerns;
failure to realize expected profitability or growth;
failure to realize expected synergies and cost savings;
coordinating geographically disparate organizations, systems and facilities; and
coordinating or consolidating corporate and administrative functions.
Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisition and current operations, which in turn, could negatively impact our results of operations.
We may fail to fully identify problems with any properties we acquire, and as such, assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities. We are actively seeking to acquire additional acreage in Texas or other regions in the future. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, adequacy of title, operating and capital costs and potential environmental and other liabilities. Although we conduct a review of properties we acquire which we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify. Such assessments are inexact and their accuracy is inherently uncertain. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface, title and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms.
Restrictions on our ability to obtain, recycle and dispose of water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner. Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local land owners and other third party sources for use in our operations. If drought conditions were to occur or demand for water were to outpace supply, our ability to obtain water could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows. In addition, significant amounts of water are produced in our operations. Inadequate access to or availability of water recycling or water disposal facilities could adversely affect our production volumes or significantly increase the cost of our operations.
Factors beyond our control affect our ability to market production and our financial results. The ability to market oil and natural gas from our wells depends upon numerous factors beyond our control. These factors could negatively affect our ability to market all of the oil or natural gas we produce. In addition, we may be unable to obtain favorable prices for the oil and natural gas we produce. These factors include:
the extent of domestic production and imports/exports of oil and natural gas;
federal regulations authorizing exports of liquefied natural gas (“LNG”), the development of new LNG export facilities under construction in the U.S. Gulf Coast region, and the first LNG exports from such facilities;
the construction of new pipelines capable of exporting U.S. natural gas to Mexico;
the proximity of hydrocarbon production to pipelines;
the availability of pipeline and/or refining capacity;
the demand for oil and natural gas by utilities and other end users;
the availability of alternative fuel sources;
the effects of inclement weather;
state and federal regulation of oil and natural gas marketing; and
federal regulation of natural gas sold or transported in interstate commerce.
In particular, in areas with increasing non-conventional shale drilling activity, pipeline, rail or other transportation capacity may be limited and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built.
The marketability ofour production is dependent upon transportation facilities and services owned and operated by third parties, and the unavailability of these facilities or services would have a material adverse effect on our revenue. Our ability to market our production depends on the availability and capacity of pipeline and other transportation operations, including trucking services, owned and operated by third parties. These facilities and services may be temporarily unavailable to us due to market conditions, physical or mechanical disruption, weather, lack of contracted capacity or other reasons. In addition, in certain newer development areas, transportation facilities and services may not be sufficient to accommodate potential production. Our failure to obtain access to transportation facilities and services on acceptable terms could materially harm our business. We may be required to shut in wells for lack of a market or because of inadequate or unavailable transportation capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. If we were required to shut in our production for long periods of time due to lack of transportation capacity, it would have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns. Exploration, development, drilling and production activities are subject to many risks. We may invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that any leasehold acreage acquired will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, including wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, wells that are profitable may not achieve our targeted rate of return.
In addition, we may not be successful in controlling our drilling and production costs to improve our overall return. We may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including among others:
unexpected drilling conditions;
pressure or irregularities in formations;
lack of proximity to and shortage of capacity of transportation facilities;
equipment failures or accidents and shortages or delays in the availability of drilling rigs, equipment, personnel and services; and
compliance with governmental requirements.
Failure to conduct our oil and gas operations in a profitable manner may result in write-downs of our proved reserves quantities, impairment of our oil and gas properties, and a write-down in the carrying value of our unproved properties, and over time may adversely affect our growth, revenues and cash flows.
Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could prevent them from being drilled or delay their drilling. Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of uncertainties, including among others:
oil and natural gas prices;
prices, the availability and cost of capital;
capital, availability and cost of drilling, completion and production services and equipment;
drilling results;
equipment, lease expirations;
gathering, marketingexpirations, regulatory approvals, and transportation constraints; and
regulatory approvals.
other factors discussed in these risk factors. Because of these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce oil or natural gas from these drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the identified locations are located, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified.
The development of our proved undeveloped reservesPUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Developing PUDs requires significant capital expenditures and successful drilling operations, and a substantial amount of our proved reserves are PUDs which may not be ultimately developed or produced. Approximately 49%43% of our total estimated proved reserves as of December 31, 2017,2021 were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations.PUDs. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantialsignificant capital expenditures are requiredwill be made to develop such reserves. We cannot be certain that the estimated costs of the development ofcapital expenditures to develop these reserves are accurate, that development will occur as scheduled, or that the results of such development will be as estimated. We may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including: unexpected drilling conditions; pressure or irregularities in formations; lack of proximity to and shortage of capacity of transportation facilities; equipment failures or accidents and shortages or delays in the availability of drilling rigs, equipment, personnel and services; the availability of capital; and compliance with governmental requirements. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reservesPUDs and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.
Risks Related to Technology
The results of our planned development programs in new or emerging shaledevelopment areasand formations may be subject to more uncertainties thanprograms in more establishedareas and formations,and may not meet our expectations for reserves or production. The results of our horizontal drilling efforts in emerging areas and formations of the Permian Basin, including Howard and Ward Counties, are generally more uncertain than drilling results in areas that are less developed and have more established production from horizontal formations such as the Wolfcamp, Spraberry and Bone Spring horizons. Because emerging areas and associated target formations have limited or no production history, we are less able to rely on past drilling results in those areas as a basis to predict our future drilling results. In addition, horizontal wells drilled in shale formations, as distinguished from vertical wells, utilize multilateral wells and stacked laterals, all of which are subject to well spacing, density and proration requirements of the Texas Railroad Commission, which requirements could adversely impact our ability to maximize the efficiency of our horizontal wells related to reservoir drainage over time. Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, access to gathering systems and takeaway capacity or otherwise, and/or natural gas and oil prices decline, our investment in these areasWe may not be as economic as we anticipate, we could incur material write-downs of unevaluated properties and the value ofable to keep pace with technological developments in our undeveloped acreage could decline in the future.
Unexpected subsurface conditions and other unforeseen operating hazards may adversely impact our ability to conduct business. There are many operating hazards in exploring for and producingindustry. The oil and natural gas including: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 may be forced by competitive pressures to implement those new technologies at substantial costs. We may not be able to respond to these competitive pressures or 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, our business, financial condition or results of operations could be materially and adversely affected.
our drilling operations may encounter unexpected formationsOur business could be negatively affected by security threats. A cyberattack or pressures, whichsimilar incident could causeoccur and result in information theft, data corruption, operational disruption, damage to equipmentour reputation or personal injury;
we may experience equipment failures which curtail or stop production;
we could experience blowouts or other damages to the productive formations that may require a well to be re-drilled or other corrective action to be taken; and
storms and other extreme weather conditions could cause damages to our production facilities or wells.
Because of these or other events, we could experience environmental hazards, including release offinancial loss. The oil and natural gas from spills, natural gas-leaks, accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or fracturing fluids, including chemical additives, underground migration, and ruptures.
If we experience any of these problems, it could affect well bores, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses in excess of our insurance coverage as a result of:
injury or loss of life;
severe damage to and destruction of property, natural resources and equipment;
pollution and other environmental damage;
clean-up responsibilities;
regulatory investigation and penalties;
suspension of our operations; and
repairs to resume operations.
We cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable to cover our possible losses from operating hazards. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect our financial condition and results of operations.
The loss of key personnel could adversely affect our ability to operate. We depend, and will continue to depend in the foreseeable future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience and expertise in evaluating and analyzing drilling prospects and producing oil and natural gas and maximizing production from oil and natural gas properties. Our ability to retain our senior officers, other key employees and our third party consultants, none of whom are subject to employment agreements, is important to our future success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business.
Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations. Our business has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, manage operations, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Unauthorized access to ourOur technologies, systems, networks, seismic data, reserves information or other proprietary information, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could otherwise lead to data corruption, communication interruption,the disruption of our business operations or other operational disruptions in our exploration or production operations. Cyberattacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain undetected for an extended period and could lead to disruptions in critical systems or the unauthorized release of confidential or otherwise protected information. These events could lead to financial losses from remedial actions, loss of business, disruption of operations, damage to our reputation or potential liability. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber-attackcyberattack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. Cyber incidents have increased, and the U.S. government has issued warnings indicating that energy assets may be specific targets of cyber securitycybersecurity threats. Our systems and
insurance coverage for protecting against cyber securitycybersecurity risks may not be sufficient. Further, as cyber-attackscyberattacks 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 vulnerability to cyber-attacks.
cyberattacks.
Risks Related to Our Indebtedness and Financial Position
Our business requires significant capital expenditures and we may not be able to obtain needed capital or financing on satisfactory terms or at all.expenditures. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Historically, we have fundedWe intend to fund our capital expenditures through a combination of cash flows from operations and, if needed, borrowings from financial institutions, the sale of public debt and equity securities, and asset dispositions. In 2017, our total operational capital expenditures, including expenditures for drilling, completion and facilities, were approximately $420 million on a cash basis ($463 million on an accrual, or GAAP, basis). Our 2018 budget for operational capital expenditures is currently estimated to be approximately $500 to $540 million (on an accrual, or GAAP, basis).divestitures. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, participation of non-operating working interest owners, the cost and availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.
If the borrowing baseability to borrow under our Credit Facility or our revenuescash flows from operations decrease, as a result of lower oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be ableThe failure to obtain debt or equityadditional financing on terms favorableacceptable to us, or at all. If cash generated by operations or cash available under our Credit Facility is not sufficient to meet our capital requirements, the failure to obtain additional financingall, could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in our estimated net proved reserves,activities and could adversely affect our business, financial condition and results of operations.
Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects. As of December 31, 2021, we had aggregate outstanding indebtedness of approximately $2.7 billion. Our amount of indebtedness could affect our operations in many ways, including:
•requiring us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities as well as any potential returns to shareholders;
•limiting management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
•increasing our vulnerability to downturns and adverse developments in our business and the economy;
•limiting our ability to access the capital markets to raise capital on favorable terms, to borrow under our Credit Facility or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;
•making 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;
•making us vulnerable to increases in interest rates as our indebtedness under our Credit Facility may vary with prevailing interest rates;
•placing us at a competitive disadvantage relative to competitors with lower levels of indebtedness or less restrictive terms governing their indebtedness; and
•making it more difficult for us to satisfy our obligations under our senior notes or other debt and increasing the risk that we may default on our debt obligations.
Restrictive covenants in our Credit Facility and the indentureagreements governing our 6.125% Senior Notesindebtedness may limit our ability to respond to changes in market conditions or pursue business opportunities.Our Credit Facility and the indentureindentures governing our 6.125% Senior Notessecond lien senior secured notes and senior notes contain restrictive covenants that limit our ability to, among other things:
incur additional indebtedness including secured indebtedness;
make investments;
merge or consolidate with another entity;
pay dividends or make certain other payments;
hedge future production or interest rates;
create liens that secure indebtedness;
repurchase securities; sell assets; and
or engage in certain other transactions without the prior consent of the holders or lenders.
As a result of these covenants, we are limited in the manner in which we conduct our business and we may be unable 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.
In addition, our Credit Facility requires us to maintain certain financial ratios and to make certain required payments of principal, premium, if any, and interest. If we fail to comply with these provisions or other financial and operating covenants in the Credit Facility andor the indentureindentures governing the 6.125 % Senior Notes,our senior notes, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default:
default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest;
interest, the lenders under our Credit Facility could elect to terminate their commitments thereunder, cease making further loans and institute foreclosure proceedings against our assets; and
we could be forced into bankruptcy or liquidation.
Adverse changes in our credit rating may affect our borrowing capacity and borrowing terms. Our outstanding debt is periodically rated by nationally recognized credit rating agencies. The credit ratings are based on our operating performance, liquidity and leverage ratios, overall financial position, and other factors viewed by the credit rating agencies as relevant to our industry and the economic outlook. Our credit rating may affect the amount and timing of availability of capital we can access, as well as the terms of
any financing we may obtain. Because we rely in part on debt financing to fund growth, adverse changes in our credit rating may have a negative effect on our future growth.
Our borrowings under our Credit Facility expose us to interest rate risk. Our earnings are exposed to interest rate risk associated with borrowings under our Credit Facility whichmake us vulnerable to increases in interest rates as they bear interest at a rate elected by us that is based on the prime, LIBOR or federal funds rate plus margins ranging from 2.00%1.00% to 3.00%, depending on the interest rate used and the amount of the loan outstanding in relation to the borrowing base. LIBOR is the subject of national, international and other regulatory guidance and proposals for reform and is currently being phased-out. At this time, it is not possible to predict how markets will respond to alternative reference rates, and the overall financial markets may be disrupted as a result of the phase-out or replacement of LIBOR. The consequences of these developments with respect to the phase-out of LIBOR cannot be predicted, but could include an increase in the cost of our borrowings under our Credit Facility.
The borrowing baseability to borrow under our Credit Facility may be reducedrestricted to an amount below the amount of borrowings outstanding under such facilities.thereunder or to a lesser amount than what we expect due to future borrowing base reductions or restrictions contained in our other debt agreements. The borrowing base and elected commitment amount under our Credit Facility is currently $700$1.6 billion, and as of December 31, 2021, we had an aggregate principal balance of $785.0 million with elected commitments of $500 million. In theoutstanding thereunder. Our borrowing base is subject to redeterminations semi-annually, and a future we may not be able to access adequate funding under our Credit Facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations. In addition, we cannot borrow amounts aboveobligations may cause us to not be able to access adequate funding under the elected commitments, even ifCredit Facility. The lenders have sole discretion in determining the amount of the borrowing base is greater, without new commitments being obtained from the lenders for such incremental amounts above the elected commitments. Ourand may cause our borrowing base is subject to redeterminations semi-annually,be redetermined to a materially lower amount, including to below our outstanding borrowings as of such redetermination. In addition, our other debt agreements contain restrictions on the incurrence of additional debt and liens which could limit our next scheduled borrowing base redetermination is expectedability to occur on or about May 2018.borrow under our Credit Facility. If our borrowing base were to be reduced, or if covenants in our indentures restrict our ability to access funding under the Credit Facility, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness. In addition, inwe cannot borrow amounts above the elected commitments, even if the borrowing base is greater, without new commitments being obtained from the lenders for such incremental amounts above the elected commitments. In the event the amount outstanding under our Credit Facility exceeds the elected commitments, we must repay such amounts immediately in cash. In the event the amount outstanding under our Credit Facility exceeds the redetermined borrowing base, we are required to either (i) grant liens on additional oil and gas properties (not previously evaluated in determining such borrowing base) with a value equal to or greater than such excess, (ii) repay such excess borrowings over six monthly installments, or (iii) elect a combination of options in clauses (i) and (ii). We may not have sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, an event of default would occur under our Credit Facility.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to certain financial, economic, competitive and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. AnyAlso, we may not be able to consummate dispositions at such time on terms acceptable to us or at all, and the proceeds of any such dispositions may not be adequate to meet such debt service obligations. Furthermore, any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. TheIn addition, the terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, anyFor example, our Credit Facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition.
Any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. Our Credit Facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.
Our leverage and debt service obligations may adversely affect our financial condition, results of operations, and business prospects. As of December 31, 2017, we had $600 million outstanding of 6.125% Senior Notes and $25 million outstanding under our Credit Facility, which had an additional $474 million available for borrowings based on the existing level of commitments. Our amount of indebtedness could affect our operations in several ways, including the following:
require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities;
limit management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
increase our vulnerability to downturns and adverse developments in our business and the economy;
limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;
place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;
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;
make us vulnerable to increases in interest rates as our indebtedness under our Credit Facility may vary with prevailing interest rates;
place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness; and
make it more difficult for us to satisfy our obligations under the 6.125% Senior Notes or other debt and increase the risk that we may default on our debt obligations.
We cannot assure yoube certain that we will be able to maintain or improve our leverage position.An element of our business strategy involves maintaining a disciplined approach to financial management. However, we are also seeking to acquire, exploit and develop additional reserves that may require the incurrence of additional indebtedness. Although we will seek to maintain or improve our leverage position, our ability to maintain or reduce our level of indebtedness depends on a variety of factors, including future performance and our future debt financing needs. General economic conditions, oil and natural gas prices and financial, business and other factors will also affect our ability to maintain or improve our leverage position. Many of these factors are beyond our control.
Risks Related to Acquisitions
We may be unable to integrate successfully the operations of acquisitions with our operations, and we may not be insured againstrealize all the anticipated benefits of these acquisitions. We have completed, and may in the future complete, acquisitions that include undeveloped acreage. We can offer no assurance that we will achieve the desired profitability from our recent acquisitions, including the Primexx Acquisition, or from any acquisitions we may complete in the future. In addition, failure to integrate future acquisitions successfully could adversely affect our financial condition and results of operations.
Our acquisitions may involve numerous risks, including those related to:
•operating a larger, more complex combined organization and adding operations;
•assimilating the assets and operations of the risksacquired business, especially if the assets acquired are in a new geographic area;
•acquired oil and natural gas reserves not being of the anticipated magnitude or as developed as anticipated;
•the loss of significant key employees, including from the acquired business;
•the inability to obtain satisfactory title to the assets we acquire;
•a decrease in our liquidity if we use a portion of our available cash to finance acquisitions;
•a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
•the diversion of management’s attention from other business concerns, which could result in, among other things, performance shortfalls;
•the failure to realize expected profitability or growth;
•the failure to realize expected synergies and cost savings;
•coordinating geographically disparate organizations, systems, data, and facilities;
•coordinating or consolidating corporate and administrative functions;
•inconsistencies in standards controls, procedures and policies; and
•integrating relationships with customers, vendors and business partners.
Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of our businesstwo companies, may not initially offset integration-related costs or achieve a net benefit in the near term or at all.
If we consummate any future acquisitions, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions. The inability to effectively manage the integration of acquisitions could reduce our focus on current operations, which in turn, could negatively impact our future results of operations.
We may fail to fully identify problems with any properties we acquire, and as such, assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities. We are actively seeking to acquire additional acreage in Texas or other regions in the future. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, adequacy of title, operating and capital costs, and potential environmental and other liabilities. Although we conduct a review that we believe is exposed from ongoing or legacy operations. In accordanceconsistent with industry practice,practices, we maintain insurance against some, but notcan give no assurance that we have identified or will identify all of the operating risks to which our business is exposed. We cannot assure you that our insurance will be adequate to cover all lossesexisting or liabilities related to our currentpotential problems associated with such properties or legacy operations. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. No assurance can be given that we will be able to maintain insurancemitigate any problems we do identify. Such assessments are inexact and their accuracy is inherently uncertain. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface, title and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in the future at ratesproperties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we consider reasonablemay not be able to acquire oil and may elect nonenatural gas properties that contain economically recoverable reserves or minimal insurance coverage. The occurrence of a significant event or claim, not fully insured or indemnified against, could have a material adverse effectbe able to complete such acquisitions on our financial condition and operations.acceptable terms.
Risks Related to Our Hedging Program
Our hedging program may limit potential gains from increases in commodity prices, or may result in losses, or may be inadequate to protect us against continuing and prolonged declines in commodity prices.We enter into hedging arrangements to hedge a portion of our production from time to time to reduce our exposure to fluctuations in oil, and natural gas, and NGL prices and to achieve more predictable cash flow. Our hedges at December 31, 20172021 are in the form of collars, swaps, put and call options, basis swaps, and other structures placed with the commodity trading branches of certain national banking institutions and with certain other commodity trading groups. These hedging arrangements may limit the benefit we could receive from increases in the market or spot prices for oil, natural gas, and natural gas.NGLs. We cannot assure yoube certain that the hedging transactions we have entered into, or will enter into, will adequately protect us from fluctuations in oil and natural gas prices. At December 31, 2017, the Company’s hedging portfolio, linked to NYMEX benchmark pricing, covers approximately 5,842 MBbls and 4,086 BBtu of our expected oil and natural gas production, respectively, for calendar year 2018. We also have commodity hedging contracts linked to Midland WTI basis differentials relative to Cushing covering approximately 5,289 MBbls of our expected oil production for calendar year 2018. These hedges may be inadequate to protect us from continuing and prolonged declines in oil, and natural gas, and NGL prices. To the extent that oil, and natural gas, and NGL prices remain at current levels or decline further, we willwould not be able to hedge future production at the same pricing level as our current hedges and our results of operations and financial condition wouldmay be negatively impacted.
We may not have production to offset hedges. Part of our business strategy is to reduce our exposure to the volatility of oil and natural gas prices by hedging a portion of our production. In addition, in a typical hedge transaction, we will have the right to receive from the other parties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the other parties this difference multiplied by the quantity hedged regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of physical production.
Our production is not fully hedged, and we are exposed to fluctuations in oil, natural gas and NGL prices and will be affected by continuing and prolonged declines in oil, natural gas and NGL prices. Our production is not fully hedged, and we are exposed to fluctuations in oil, natural gas and NGL prices and will be affected by continuing and prolonged declines in oil, natural gas and NGL prices. The total volumes which we hedge through use of our derivative instruments varies from period to period and takes into account our view of current and future market conditions in order to provide greater certainty of cash flows to meet our debt service costs and capital program. We generally hedge for the next 12 to 24 months, subject to the covenants under our Credit Facility. We intend to continue to hedge our production, but we may not be able to do so at favorable prices. Accordingly, our revenues and cash flows are subject to increased volatility and may be subject to significant reduction in prices which would have a material negative impact on our results of operations.
Our hedging transactions expose us to counterparty credit risk. Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract.contract, particularly during periods of falling commodity prices. Disruptions in the financial markets or other factors outside our control could lead to sudden decreases in a
counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. During periods of falling commodity prices, our hedging transactions expose us to risk of financial loss if our counterparty to a derivatives transaction fails to perform its obligations under a derivatives transaction. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Evenperform, and even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending uponon market conditions.conditions at the time. If the creditworthiness of any of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.
The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results. Our principal exposures to credit risk are through receivables resulting from the sale of our oil and natural gas production, which we market to energy marketing companies, refineries and affiliates, advances to joint interest parties and joint interest receivables. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The largest purchaser of our oil and natural gas accounted for approximately 29% of our total oil and natural gas revenues for the year ended December 31, 2017. We do not require any of our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
We have no plans to pay cash dividends on our common stock in the foreseeable future.The terms of our Credit Facility contain limitations that impact our ability to pay dividends and make other distributions. In addition, any future determination as to the declaration and payment of cash dividends will be at the discretion of our Board of Directors and will depend upon our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors deemed relevant by our Board of Directors.
Legal and Regulatory Risks
We are subject to stringent and complex federal, state and local laws and regulations which require compliance that could result in substantial costs, delays or penalties.Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. For a discussion of the material regulations applicable to us, see “Regulations.“Business and Properties—Regulations.” These laws and regulations may:
•require that we acquire permits before commencing drilling;
•regulate the spacing of wells and unitization and pooling of properties;
•impose limitations on production or operational, emissions control and other conditions on our activities;
•restrict the substances that can be released into the environment or used in connection with drilling and production activities or restrict the disposal of waste from our operations;
•limit or prohibit drilling activities on protected areas, such as wetlands wilderness or other protected areas;and wilderness;
•impose penalties andor other sanctions for accidental and/or unpermitted spills or releases from our operations; andor
•require measures to remediate or mitigate pollution and environmental impacts from current and former operations, such as cleaning up spills or dismantlingdecommissioning abandoned wells and production facilities.
Significant expenditures may be required to comply with governmental laws and regulations applicable to us. In addition, failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, permit revocations, requirements for additional pollution controls or injunctions limiting or prohibiting operations.
The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as emissions monitoring and control, permitting, or waste handling, permitting,storage, transport, remediation or cleanupdisposal for the oil and natural gas industry and could have a significant impact on our operating costs. In general, the oil and natural gas industry recently has been the subject of increased legislative and regulatory attention with respect to public health and environmental matters. Even if regulatory burdens temporarily ease from time to time, the historic trend of more expansive and stricter environmental legislation and regulations may continue in the long-term.
Further, under these laws and regulations, we could be liable for costs of investigation, removal and remediation, damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of increased public services, as well as administrative, civil and criminal fines and penalties, and injunctive relief. Certain environmental statutes, including the RCRA, CERCLA, OPA and analogous state laws and regulations, impose strict, joint and several liability for costs required to investigate, clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released.released (i.e., liability may be imposed regardless of whether the current owner or operator was responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time the release or contamination occurred). We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change, greenhouse gasesengine and other
equipment emissions, GHGs and hydraulic fracturing. Under the common law, we could be liable for injuries to people and property. We maintain limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Also, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and
accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability in excess of our insurance coverage or we may be required to curtail or cease production from properties in the event of environmental incidents.
Federal legislation and state and local legislative and regulatory initiatives relating to hydraulic fracturing and water disposal wells could result in increased costs and additional operating restrictions or delays. Hydraulic fracturing is used to stimulate production of hydrocarbons particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production and is typically regulated by state oil and gas commissions. However, from time to time, the U.S. Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing. Legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of "underground injection,"“underground injection” and to require federal permitting and regulatory control of hydraulic fracturing and to require disclosure of the chemical constituents of the fluids used in the fracturing process.but has not passed. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position thatregulates hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection ControlUIC program, specifically as "Class II"“Class II” Underground Injection Control wells under the Safe Drinking Water Act. The EPA has also published air emissionrecently taken steps to strengthen its methane standards, including most recently in November 2021, when the EPA issued a proposed rule intended to reduce methane emissions from oil and gas sources. The proposed rule would make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain equipment, processessource types that have never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and activities acrossliquids unloading facilities). In addition, the proposed rule would establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by EPA. Under the proposed rule, states would have three years to develop their compliance plan for existing sources and the regulations for new sources would take effect immediately upon issuance of a final rule. The EPA is expected to issue both a supplemental proposed rule, which may expand or modify the current proposed rule, and final rule by the end of 2022. The scope of future obligations remains uncertain; however, given the long-term trend towards increasing regulation, future federal regulation of methane and other greenhouse gas emissions from the oil and natural gas sector. In addition, the BLM previously published final rules governing hydraulic fracturing on federal and Indian lands, which rules have been rescinded or suspended, but litigation is ongoing regarding the rules.
industry remains a possibility.
In some areas of Texas, including the Eagle Ford and Permian, there has been concern that certain formations into which disposal wells are injecting produced waters could become over-pressured after many years of injection, and the governing Texas regulatory agencyRRC is reviewing the data to determine whether any regulatory action is necessary to address this issue. If the Texas state agencyRRC were to decline to issue permits for, or limitimpose new limits on the volumes of, new injection wells into the formations that we currently utilized by us,utilize, we may be required to seek alternative methods of disposing of produced waters, including injecting into deeper formations, which could increase our costs.
Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, impose additional requirements on hydraulic fracturing activities or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, pursuant to legislation adopted by the State of Texas in June 2011,law requires the chemical components used in the hydraulic fracturing process, as well as the volume of water used, must be disclosed to the RRC and the public. Furthermore, in 2013, the RRC issued the "wellThe RRC’s “well integrity rule," whichrule” includes new testing and reporting requirements, such as (i) the requirement to submit to the RRC cementing reports after well completion or cessation of drilling, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. Additionally, in 2014 the RRC adopted a rule requiringrules require applicants for certain new water disposal wells to conduct seismic activity searches using the U.S. Geological Survey to determine the potential for earthquakes within a circular area of 100 square miles. The rule also clarifiesFurther, the RRC'sRRC has authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The RRC has used this authority to deny permits for, wasteand limit volumes for, disposal wells. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of drilling in general and/or hydraulic fracturing in particular.
In December 2016,The EPA issued the EPA released its final report “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States.” ThisStates” report, concludesconcluding that hydraulic fracturing can impact drinking water resources in certain circumstances but also noted that certain datedata gaps and uncertainties limited EPA’s assessment.ability to fully characterize the severity of impacts or calculate the national frequency of impacts on drinking water resources from activities in the hydraulic fracturing water cycle. This study could result in additional regulatory scrutiny that could make it difficultrestrict our ability to perform hydraulic fracturing and increase our costs of compliance and doing business.
There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, water usage and the potential for impacts to surface water, groundwater and the environment generally, and a number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. Several states and municipalities have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances. If new laws or regulations that significantly restrict hydraulic fracturing or water
disposal wells are adopted, such laws could make it more difficult or costly for us to drill for and produce oil and natural gas as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements, permitting delays and potential increases in costs. These changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.
Climate change legislation or regulations restricting emissions of “greenhouse gases” (“GHG”)GHG, changes in the availability of financing for fossil fuel companies, and physical effects from climate change could result in increasedadversely impact our operating costs and reduced demand for the oil and natural gas we produce. In recent years, federal, state and local governments have taken
steps to reduce emissions of greenhouse gases.GHGs. The EPA has finalized a series of greenhouse gasGHG monitoring, reporting and emissions control rules for the oil and natural gas industry,proposed additional rules, and the U.S. Congress has, from time to time, considered adopting legislation to reduce or tax emissions. Several states have already taken measures to reduce emissions of greenhouse gasesGHGs primarily through the development of greenhouse gasGHG emission inventories and/or regional greenhouse gasGHG cap-and-trade programs. While we are subject to certain federal greenhouse gasGHG monitoring and reporting requirements, our operations currently are not adversely impacted by existing federal, state and local climate change initiatives. For a description of some existing and proposed greenhouse gasGHG rules and regulations, see “Regulations.“Business and Properties—Regulations.”
In December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in Paris, France. The resultingnearly 200 countries, including the United States, coming together to develop the Paris Agreement, which calls for the parties to undertake "ambitious efforts"“ambitious efforts” to limit the average global temperature and to conserve and enhance sinks and reservoirs of GHGs.temperature. The Paris Agreement went into effect on November 4, 2016. The Paris Agreement2016, and establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. However, onOn June 1, 2017, President Trump announced that the United StatesU.S. would withdraw from the Paris Agreement. It is not clear what stepsAgreement and completed the Trump Administration plans to take to withdrawprocess of withdrawing from the Paris Agreement whetheron November 4, 2020. However, on January 20, 2021, President Biden issued written notification to the United Nations of the United States’ intention to rejoin the Paris Agreement, which became effective on February 19, 2021. In addition, in September 2021, President Biden publicly announced the Global Methane Pledge, a new agreement can be negotiated,pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030. Since its formal launch at the COP26, over 100 countries have joined the pledge. The COP26 concluded with the finalization of the Glasgow Pact, which stated long-term global goals (including those in the Paris Agreement) to limit the increase in the global average temperature and emphasized reductions in GHG emissions. In addition, a number of states have begun taking actions to control or what terms would be included in such an agreement.reduce emissions of GHGs. Restrictions on GHG emissions that may be imposed could adversely affect the oil and gas industry. The adoption of legislation or regulatory programs to reduce GHG emissions 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 requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Moreover, incentives or requirements to conserve energy, use alternative energy sources, reduce GHG emissions in product supply chains, and increase demand for low-carbon fuel or zero-emissions vehicles, could reduce demand for the oil and natural gas we produce. International commitments, re-entry into the Paris Agreement, and President Biden’s executive orders may result in the development of additional regulations or changes to existing regulations. At the federal level, although no comprehensive climate change legislation has been implemented to date, such legislation has periodically been introduced in the U.S. Congress and may be proposed or adopted in the future. The likelihood of such legislation has increased due to the current administration. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations.
Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact theIn addition, fuel conservation measures, alternative fuel requirements and increasing consumer demand for price of,alternatives to oil and value of our productsnatural gas could reduce demand for oil and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increase our own costs. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.
In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves.natural gas. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere withimpact our business activities, operations and ability to access capital. Furthermore, some parties have initiated public nuisance claims have been madeunder federal or state common law against certain energy companies alleging that GHG emissions frominvolved in the production of oil and natural gas operations constitute a public nuisance under federal and/or state common law.gas. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. Although our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.
Finally, most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere and climate change may produce significant physical effects on weather conditions, such as increased frequency and severity of droughts, storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from winds or floods, increases in our costs of operation, or reductions in the efficiency of our operations, impacts on our personnel, supply chain, or distribution chain, as well as potentially increased costs for insurance coverages in the aftermath of such effects. Our ability to mitigate
the adverse physical impacts of climate change depends in part upon our disaster preparedness and response and business continuity planning.
Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation of over-the-counter derivatives and requires the U.S. Commodity Futures Trading Commission (the “CFTC”)CFTC and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the over-the-counter market.
Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas, andincluding the scope of relevant definitions and/or exemptions, still remain to be finalized. In one of the CFTC’s rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC has proposed but not yet approved position limits for certain futures and options contracts in various commodities and for swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions). Similarly, the CFTC has proposed but not yet finalized a rule regarding the capital that a swap dealer or major swap participant is required to post with respect to its swap business has not yet issued a final rule.pending. The CFTC has issued a final rule on margin requirements for uncleared swap transactions in January 2016, which it amended in November 2018. The final rule as amended includes an exemption for certain commercial end-users that enter into uncleared swaps in order to hedge bona fide commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exception from the requirement to use cleared exchanges (rather than hedging over-the-counter) for commercial end-users who use swaps to hedge their commercial risks. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations. On January 24, 2020, U.S. banking regulators published a new approach for calculating the quantum of exposure of derivative contracts under their regulatory capital rules. This approach to measuring exposure is referred to as the standardized approach for counterparty credit risk or SA-CCR. It requires certain financial institutions to comply with significantly increased capital requirements for over-the-counter commodity derivatives beginning on January 1, 2022. In addition, on September 15, 2020, the CFTC issued a final rule regarding the capital a swap dealer or major swap participant is required to set aside with respect to its swap business, which has a compliance date of October 6, 2021. These two sets of regulations and the increased capital requirements they place on certain financial institutions may reduce the number of products and counterparties in the over-the-counter derivatives market available to us and could result in significant additional costs being passed through to end-users like us. On January 14, 2021, the CFTC published a final rule on position limits for certain commodities futures and their economically equivalent swaps, though like several other rules there is a bona fide hedging exemption to the application of such rule. All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business.
While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or capital requirements, dependingDepending on our ability to satisfy the CFTC’s requirements for the various exemptions available for a commercial end-user using swaps to hedge or mitigate its commercial risks, thesethe final rules and regulations may provide beneficial exemptions and/or may require us to comply with position limits and other limitations with respect to our financial derivative activities. When aAfter the compliance date for the final rule on capital requirements, is
issued, the Dodd-Frank Act may require our current counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which could increase the cost to us of entering into such derivatives. The Dodd-Frank Act may also require our current counterparties to financial derivative transactions to cease their current business as hedge providers or spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties, and may cause some entities to cease their current business as hedge providers.counterparties. These potential changes could reduce the liquidity of the financial derivatives markets which would reduce the ability of commercial end-users like us to hedge or mitigate their exposure to commodity price volatility. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of future swaps relative to the terms of our existing financial derivative contracts, and reduce the availability of derivatives to protect against commercial risks we encounter.
In addition, federal banking regulators have adopted new capital requirements for certain regulated financial institutions in connection with the Basel III Accord. The Federal Reserve Board also issued proposed regulations on September 30, 2016, proposing to impose higher risk-weighted capital requirements on financial institutions active in physical commodities, such as oil and natural gas. If and when these proposed regulations are fully implemented, financial institutions subject to these higher capital requirements may require that we provide cash or other collateral with respect to our obligations under the financial derivatives and other contracts in order to reduce the amount of capital such financial institutions may have to maintain. Alternatively, financial institutions subject to these capital requirements may require premiums to enter into derivatives and other physical commodity transactions to compensate for the additional capital costs for these transactions. Rules implementing the Basel III Accord and higher risk-weighted capital requirements could materially reduce our liquidity and increase the cost of derivative contracts and other physical commodity contracts (including through requirements to post collateral which could adversely affect our available capital for other commercial operations purposes).
If we reduce our use of derivative contracts as a result of any of the foregoing new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas and natural gas liquids prices, which some legislators attributed to speculative trading in derivatives and commodity instruments. Our revenues could t be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows.
Tax Risks
Our ability to use our existing net operating loss (“NOL”) carryforwards or other tax attributes could be limited. A significant portion of our NOL carryforward balance was generated prior to the effective date of limitations on utilization of NOLs imposed by the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) and are allowable as a deduction against 100% of taxable income in future years, but will start to expire in the 2035 taxable year. The remainder were generated following such effective date, and thus generally allowable as a deduction against 80% of taxable income in future years (with an exception to this rule due to the enactment of the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”), whereby the utilization of NOLs was temporarily expanded for taxable years beginning before 2021). Utilization of any NOL carryforwards depends on many factors, including our ability to generate future taxable income, which cannot be assured. In addition, Section 382 (“Section 382”) of the Internal Revenue Code of 1986, as amended (the “Code”), generally imposes, upon the occurrence of an ownership change (discussed below), an annual limitation on the amount of our pre-ownership change NOLs we can utilize to offset our taxable income in any taxable year (or portion thereof) ending after such ownership change. The limitation is generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax exempt rate. In general, an ownership change occurs if there is a cumulative increase in our ownership of more than 50 percentage points by one or more “5% shareholders” (as defined in the Code) at any time
during a rolling three-year period. Future ownership changes and/or future regulatory changes could further limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows once we attain profitability.
Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of our income or other tax returns could adversely affect our financial condition and results of operations. We are subject to income taxes in the U. S., and our domestic tax assets and liabilities are subject to the allocation of expenses in differing jurisdictions. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including the following: changes in the valuation of our deferred tax assets and liabilities; expected timing and amount of the release of any tax valuation allowances; tax effects of stock-based compensation; costs related to intercompany restructurings; changes in tax laws, regulations or interpretations thereof; or lower than anticipated future earnings in our taxing jurisdictions. In addition, we may be subject to audits of our income, sales and other transaction taxes by U.S. federal and state authorities. Outcomes from these audits could have an adverse effect on our financial condition and results of operations.
Tax laws and regulations may change over time and the recently passed comprehensive tax reform billsuch changes could adversely affect our business and financial condition.On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the "Tax Act") that significantly reforms the Internal Revenue Code of 1986, as amended (the "Code"). The Tax Act, among other things, (i) permanently reduces the U.S. corporate income tax rate, (ii) repeals the corporate alternative minimum tax, (iii) eliminates the deduction for certain domestic production activities, (iv) imposes new limitations on the utilization of net operating losses, and (v) provides for more general changes to the taxation of corporations, including changes to cost recovery rules and to the deductibility of interest expense, which may impact the taxation of oil and gas companies. The Tax Act is complex and far-reaching and we cannot predict with certainty the resulting impact its enactment has on us. The ultimate impact of the Tax Act may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional regulatory guidance that may be issued and any such changes in interpretations or assumptions could adversely affect our business and financial condition. See Note 11 to our consolidated financial statements included elsewhere in this Annual Report for additional information.
In addition, from From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws, including (i) the elimination of the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentagechanges to a depletion allowance for oil and natural gas properties, and (iii) the implementation of a carbon tax, (iv) an extension of the amortization period for certain geological and geophysical expenditures.expenditures, (v) changes to tax rates, and (vi) the introduction of a minimum tax. While these specific changes arewere not included in the Tax Act or the CARES Act, no accurate prediction can be made as to whether any such legislative changes or other changes (such as those contained in the Build Back Better Act) will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. The elimination of such U.S. federal tax deductions, as well as any other changes to or the imposition of new federal, state, local or non-U.S. taxes (including the imposition of, or increases in production, severance or similar taxes) could adversely affect our business and financial condition.
Other Material Risks
Competitive industry conditions may negatively affect our ability to conduct operations. We compete with numerous other companies in virtually all facets of our business. Our competitors in development, exploration, acquisitions and production include major integrated oil and gas companies and smaller independents as well as numerous financial buyers. Some of our competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit. We also compete for the materials, equipment, personnel and services that are necessary for the exploration, development and operation of our properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development.
All of our producing properties are located in the Permian of West Texas and the Eagle Ford of South Texas, making us vulnerable to risks associated with operating in only two geographic regions. As a result of this concentration, as compared to companies that have a more diversified portfolio of properties, we may be disproportionately exposed to the impact of regional supply and demand factors, severe weather, delays or interruptions of production from wells in this area caused by governmental regulation, specific taxes or other regulatory legislation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services, or market limitations or interruption of the processing or transportation of oil, natural gas or NGLs. Such delays, interruptions or limitations could have a material adverse effect on our financial condition and results of operations. In addition, the effect of fluctuations on supply and demand may be more pronounced within specific geographic oil and natural gas producing areas, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions.
The results of our planned development programs in new or emerging shale development areas and formations may be subject to more uncertainties than programs in more established areas and formations, and may not meet our expectations for reserves or production. The results of our horizontal drilling efforts in emerging areas and formations of the Permian are generally more uncertain than drilling results in areas that are more developed and have more established production from horizontal formations. Because emerging areas and associated target formations have limited or no production history, we are less able to rely on past drilling results in those areas as a basis to predict our future drilling results. In addition, horizontal wells drilled in shale formations, as distinguished from vertical wells, utilize multilateral wells and stacked laterals, all of which are subject to well spacing, density and proration requirements of the RRC, which requirements could adversely impact our ability to maximize the efficiency of our horizontal wells related to reservoir drainage over time. Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results in these areas are less than anticipated or we are unable to execute our drilling program in these areas because of capital constraints, access to gathering systems and takeaway capacity or otherwise, or natural gas and oil prices decline, our investment in these areas may not be as economic as we anticipate, we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.
The loss of key personnel, or inability to employ a sufficient number of qualified personnel, could adversely affect our ability to operate. We depend, and will continue to depend in the foreseeable future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience and expertise in evaluating and analyzing drilling prospects and producing oil and natural gas and maximizing production from oil and natural gas properties. Our ability to retain our senior officers, other key employees, and third party consultants, many of whom are not subject to employment agreements, is important to our future success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business. Also, we may experience employee turnover or labor shortages if our business requirements, compensation, benefits and/or perquisites are inconsistent with the expectations of current or prospective employees, or if workers pursue employment in fields with less volatility than in the energy industry. If we are unsuccessful in our efforts to attract and retain sufficient qualified personnel on terms acceptable to us, or do so at rates necessary to maintain our competitive position, our business could be adversely affected.
The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results.Our principal exposure to credit risk is through receivables resulting from the sale of our oil and natural gas production, advances to joint interest parties and joint interest receivables. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The largest purchaser of our oil and natural gas accounted for approximately 20% of our total revenues for the year ended December 31, 2021. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
Our bylaws designate the Court of Chancery of the State of Delaware (the “Court of Chancery”) as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our shareholders, which could limit our shareholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, or other employees. Our bylaws provide that, unless we consent in writing to the selection of an alternative forum, the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action or proceeding asserting a claim for breach of a fiduciary duty owed by any current or former director, officer, or other employee of our company to us or our shareholders, (iii) any action or proceeding asserting a claim against us or any current or former director, officer, or other employee of our company arising pursuant to any provision of the Delaware General Corporate Law (the “DGCL”) or our charter or bylaws (as each may be amended from time to time), (iv) any action or proceeding asserting a claim against us or any current or former director, officer, or other employee of our company governed by the internal affairs doctrine, or (v) any action or proceeding as to which the DGCL confers jurisdiction on the Court of Chancery shall be the Court of Chancery or, if and only if the Court of Chancery lacks subject matter jurisdiction, any state court located within the State of Delaware or, if and only if such state courts lack subject matter jurisdiction, the federal district court for the District of Delaware, in all cases to the fullest extent permitted by law and subject to the court’s having personal jurisdiction over the indispensable parties named as defendants.
Our exclusive forum provision is not intended to apply to claims arising under the Securities Act or the Exchange Act. To the extent the provision could be construed to apply to such claims, there is uncertainty as to whether a court would enforce the forum selection provision with respect to such claims, and in any event, our shareholders would not be deemed to have waived our compliance with federal securities laws and the rules and regulations thereunder.
Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock is deemed to have received notice of and consented to the foregoing forum selection provision. This provision may limit our shareholders’ ability to bring a claim in a judicial forum that they find favorable for disputes with us or our directors, officers, or other employees, which may discourage such lawsuits. Alternatively, if a court were to find this choice of forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect its business, financial condition, prospects, or results of operations.
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 the Company or a merger in which we are not the surviving company and may otherwise prevent or slow changes in our boardBoard of directorsDirectors 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.DGCL. These provisions could discourage an acquisition of the Company 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.
We have no current plans to pay cash dividends on our common stock. Our Credit Facility and the indentures governing our senior notes limit our ability to pay dividends and make other distributions. We have no current plans to pay dividends on our common stock and any future determination as to the declaration and payment of cash dividends will be at the discretion of our Board of Directors and will depend upon our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors deemed relevant by our Board of Directors at the time of such determination. Consequently, unless we revise our dividend plans, a shareholder’s only opportunity to achieve a return on its investment in us will be by selling its shares of
our common stock at a price greater than the shareholder paid for it. There is no guarantee that the price of our common stock that will prevail in the market will exceed the price at which a shareholder purchased its shares of our common stock.None.
We are a defendant in various legal proceedings and claims, which arise in the ordinary course of our business. We do notWhile the outcome of these events cannot be predicted with certainty, we believe that the ultimate resolution of any such actions will not have a material effect on our financial position or results of operations.
Not applicable.
PART II.
ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
Our common stock trades on the New York Stock Exchange (“NYSE”) under the symbol “CPE”.
Reverse Stock Split
On August 7, 2020, the Board of Directors effected a reverse stock split of the Company’s outstanding shares of common stock at a ratio of 1-for-10 and proportionately reduced the total number of authorized shares from 525,000,000 to 52,500,000 shares. The following table sets forthCompany’s common stock began trading on a split-adjusted basis on the highNYSE at the market open on August 10, 2020. All share and low sale prices per share amounts in this Annual Report on Form 10-K for periods prior to August 7, 2020 have been retroactively adjusted to reflect the reverse stock split. The par value of the common stock was not adjusted as reported fora result of the periods indicated.
|
| | | | | | | | | | | | | | | | |
| | Common Stock Price |
| | 2017 | | 2016 |
| | High | | Low | | High | | Low |
First quarter | | $ | 16.32 |
| | $ | 10.97 |
| | $ | 9.05 |
| | $ | 4.21 |
|
Second quarter | | 13.92 |
| | 9.63 |
| | 12.56 |
| | 8.15 |
|
Third quarter | | 11.74 |
| | 9.34 |
| | 15.91 |
| | 10.34 |
|
Fourth quarter | | 12.50 |
| | 9.76 |
| | 18.53 |
| | 12.45 |
|
reverse stock split.
Holders
As of February 23, 201818, 2022 the Company had approximately 2,7151,182 common stockholders of record.
Dividends
We have not paid any cash dividends on our common stock to date and presently do not expect to declare or pay any cash dividends on our common stock in the foreseeable future as we intendnear-term focus is to reinvest our cash flows and earnings into our business. The declarationbusiness and paymentcontinue to pay down debt. However, we continuously monitor many internal and external factors as we consider when, or if, we should implement shareholder return programs. These factors include our current and projected financial performance; our debt metrics, covenants and absolute amounts borrowed; commodity price outlooks; cash requirements; corporate and strategic plans; macroeconomic indicators; among other items. Ultimately, the timing, amount and form of future dividends, if any, is subject to the discretion of our Board of Directors and to certain limitations imposed under Delaware corporate law and the agreements governing our debt obligations. The timing, amount and form of dividends, if any, will depend on, among other things, our results of operations, financial condition, cash requirements and other factors deemed relevant by our Board of Directors. In addition, certain of our debt facilities contain restrictions on the payment of dividends to the holders of our common stock.
Holders of our 10% Series A Cumulative Preferred Stock are entitled to a cumulative dividend whether or not declared, of $5.00 per annum, payable quarterly, equivalent to 10.0% of the liquidation preference of $50.00 per share. Unless the full amount of the dividends for the 10% Series A Cumulative Preferred Stock is paid in full, we cannot declare or pay any dividend on our common stock.
During 2017, neither the Company nor any affiliated purchasers made repurchases of Callon’s equity securities.
On February 4, 2016, a total of 120,000 shares of the Company’s 10% Series A Cumulative Preferred Stock were exchanged for 719,000 shares of common stock.
Equity Compensation Plan Information
The following table summarizes information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2017 (securities amounts are presented in thousands).
|
| | | | | | | | | | |
Plan Category | | Number of Securities to be Issued Upon Exercise of Outstanding Options | | Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights | | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans |
Equity compensation plans approved by security holders | | — |
| | $ | — |
| | 1,338 |
|
Equity compensation plans not approved by security holders | | — |
| | $ | — |
| | — |
|
Total | | — |
| | $ | — |
| | 1,338 |
|
For additional information regarding the Company’s benefit plans and share-based compensation expense, see Notes 8 and 9 in the Footnotes to the Financial Statements.
Performance Graph
The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the performance of the Company’s common stock relative to twoa broad-based stock performance indices.index and a peer group of companies. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance.
The stock price performance graph below compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the Standard & Poor’s 500 Index (“S&P 500 Index”) and a peer group of companies to which we compare our performance from December 31, 2016 through December 31, 2021. The companies in the peer group include Centennial Resource Development, Inc., Dow Jones US SelectLaredo Petroleum, Inc., Magnolia Oil & Gas ExplorationCorporation, Matador Resources, Inc., PDC Energy, Inc., Ranger Oil Corporation and Production Index (“DJ US Select O&G E&P Index”) and Susquehanna International Group, LLP Oil Exploration & Production Index (“SIG Oil E&P Index”) from December 31, 2012, through December 31, 2017.SM Energy Company. The SIG Oil E&P Index is no longer an active index and the Company plans to replace it with the DJ US Select O&G E&P Index, which is commonlyCompany’s historical stock prices used by the Company’s peer group. Consequently, this index has been added toin the graph below and we expecthave been retroactively adjusted to include it in future year’s performance graphs.
reflect the Company’s 1-for-10 reverse stock split effective August 7, 2020.
The stock price performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933 or Securitiesthe Exchange Act, of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.filing
Comparison of Five YearCumulative Total Return
Assumes Initial Investment of $100
December 201731, 2021
![](https://files.capedge.com/10-K/0000928022-18-000013/chart-eab4457fda511566037.jpg)
![cpe-20211231_g1.jpg](https://files.capedge.com/10-K/0000928022-22-000027/cpe-20211231_g1.jpg)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
Company/Market/Peer Group | | 2016 | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 |
Callon Petroleum Company | | $100 | | | $79 | | | $42 | | | $31 | | | $9 | | | $31 | |
S&P 500 Index - Total Returns | | 100 | | | 122 | | | 116 | | | 153 | | | 181 | | | 233 | |
Peer Group | | 100 | | | 85 | | | 63 | | | 51 | | | 26 | | | 85 | |
Unregistered Sales of Equity Securities and Use of Proceeds
Pursuant to the closing of the Primexx Acquisition, the Company issued 8.84 million shares of the Company’s common stock as a portion of the total consideration for the assets acquired. Also pursuant to the Primexx PSAs, certain interest owners exercised their option to sell their interest in the properties included in the Primexx Acquisition to the Company for consideration equal to 0.2 million shares of the Company’s common stock.
Pursuant to the closing of the Second Lien Note Exchange, the Company exchanged $197.0 million of its outstanding Second Lien Notes for a notional amount of approximately $223.1 million of its common stock, which equated to 5.5 million shares.
All shares issued pursuant to the Primexx Acquisition and the Second Lien Note Exchange were issued in reliance upon the exemption from the registration requirements of the Securities Act provided by Section 4(a)(2) of the Securities Act as sales by an issuer not involving any public offering. The issuance of such shares in connection with the Primexx Acquisition and the Second Lien Note Exchange did not involve a public offering for purposes of Section 4(a)(2) because of, among other things, it was being made only to accredited investors, and in connection therewith, the Company did not engage in general solicitation or advertising with regard to the issuance of such shares.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
Company/Market/Peer Group | | 2012 | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
Callon Petroleum Company | | $ | 100.00 |
| | $ | 138.94 |
| | $ | 115.96 |
| | $ | 177.45 |
| | $ | 327.02 |
| | $ | 258.51 |
|
S&P 500 Index - Total Returns | | 100.00 |
| | 132.39 |
| | 150.51 |
| | 152.59 |
| | 170.84 |
| | 208.14 |
|
DJ US Select O&G E&P | | 100.00 |
| | 131.24 |
| | 115.57 |
| | 87.27 |
| | 109.82 |
| | 110.58 |
|
SIG Oil Exploration & Production Index | | 100.00 |
| | 128.46 |
| | 91.28 |
| | 48.44 |
| | 62.74 |
| | 62.74 |
|
ITEM 6. Selected Financial DataReserved
The following table sets forth, as of the dates and for the periods indicated, selected financial information about the Company. The financial information for each of the five years in the period ended December 31, 2017 has been derived from our audited Consolidated Financial Statements for such periods. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and Notes thereto. The following information is not necessarily indicative of our future results (dollars in thousands, except per share amounts).
|
| | | | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
Statement of Operations Data | | |
Operating revenues | | | | | | | | | | |
Oil and natural gas sales | | $ | 366,474 |
| | $ | 200,851 |
| | $ | 137,512 |
| | $ | 151,862 |
| | $ | 102,569 |
|
Operating expenses | | | | | | | | | | |
Total operating expenses | | $ | 225,028 |
| | $ | 248,328 |
| | $ | 346,622 |
| | $ | 113,592 |
| | $ | 91,905 |
|
Income (loss) from operations | | 141,446 |
| | (47,477 | ) | | (209,110 | ) | | 38,270 |
| | 10,664 |
|
Net income (loss) (a) | | 120,424 |
| | (91,813 | ) | | (240,139 | ) | | 37,766 |
| | 4,304 |
|
Income (loss) per share ("EPS") | | | | | | | | | | |
Basic | | $ | 0.56 |
| | $ | (0.78 | ) | | $ | (3.77 | ) | | $ | 0.67 |
| | $ | (0.01 | ) |
Diluted | | $ | 0.56 |
| | $ | (0.78 | ) | | $ | (3.77 | ) | | $ | 0.65 |
| | $ | (0.01 | ) |
Weighted average shares outstanding for Basic EPS | | 201,526 |
| | 126,258 |
| | 65,708 |
| | 44,848 |
| | 40,133 |
|
Weighted average shares outstanding for Diluted EPS | | 202,102 |
| | 126,258 |
| | 65,708 |
| | 45,961 |
| | 40,133 |
|
Statement of Cash Flows Data | | | | | | | | | | |
Net cash provided by operating activities | | $ | 229,891 |
| | $ | 120,774 |
| | $ | 89,319 |
| | $ | 94,387 |
| | $ | 54,475 |
|
Net cash used in investing activities | | (1,072,532 | ) | | (866,287 | ) | | (259,160 | ) | | (452,501 | ) | | (79,804 | ) |
Net cash provided by (used in) financing activities | | 217,643 |
| | 1,397,282 |
| | 170,097 |
| | 356,070 |
| | 27,202 |
|
Balance Sheet Data | | | | | | | | | | |
Total oil and natural gas properties | | $ | 2,513,491 |
| | $ | 1,475,401 |
| | $ | 711,386 |
| | $ | 742,155 |
| | $ | 324,187 |
|
Total assets | | 2,693,296 |
| | 2,267,587 |
| | 788,594 |
| | 863,346 |
| | 423,953 |
|
Long-term debt (b) | | 620,196 |
| | 390,219 |
| | 328,565 |
| | 321,576 |
| | 75,748 |
|
Stockholders' equity | | 1,855,966 |
| | 1,733,402 |
| | 362,758 |
| | 433,735 |
| | 279,094 |
|
Proved Reserves Data | | | | | | | | | | |
Total oil (MBbls) | | 107,072 |
| | 71,145 |
| | 43,348 |
| | 25,733 |
| | 11,898 |
|
Total natural gas (MMcf) | | 179,410 |
| | 122,611 |
| | 65,537 |
| | 42,548 |
| | 17,751 |
|
Total (MBOE) | | 136,974 |
| | 91,580 |
| | 54,271 |
| | 32,824 |
| | 14,857 |
|
Standardized measure (c) | | $ | 1,556,682 |
| | $ | 809,832 |
| | $ | 570,890 |
| | $ | 579,542 |
| | $ | 283,946 |
|
| |
(a) | Net loss for 2015 included the recognition of a write-down of oil and natural gas properties of $208,435 as a result of the ceiling test limitation and $108,843 of income tax expense related to the recognition of a valuation allowance. Net loss for 2016 included the recognition of a write-down of oil and natural gas properties of $95,788 as a result of the ceiling test limitation. See Notes 11 and 13 in the Footnotes to the Financial Statements for additional information. |
| |
(b) | See Note 5 in the Footnotes to the Financial Statements for additional information. |
| |
(c) | Standardized measure is the future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet. Prices are based on either the preceding 12-months’ average price, based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. Future production and development costs are based on current estimates with no escalations. Estimated future cash flows have been discounted to their present values based on a 10% discount rate. See Note 13 in the Footnotes to the Financial Statements for additional information. |
|
| | |
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operation | |
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
The following management’s discussion and analysis describes the principal factors affecting the Company’sour results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying audited consolidated financial statements, information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results, which are included in various parts of this filing. Our website address is www.callon.com. All
A discussion and analysis of our filingsthe Company’s financial condition and results of operations for the year ended December 31, 2019 can be found in “Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” of its Annual Report on Form 10-K for the year ended December 31, 2020, which was filed with the SEC are available free of charge through our website as soon as reasonably practicable after we file them with, or furnish them to, the SEC. Information on our website does not form part of this report on Form 10-K.February 25, 2021.
General
We are an independent oil and natural gas company established in 1950. We are focused on the acquisition, development, exploration and exploitationdevelopment of unconventional, onshore, oil and natural gas reserveshigh-quality assets in the Permian Basin. Theleading oil plays of South and West Texas. Our activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin is located in West Texas, and southeastern New Mexico and is comprised of three primary sub-basins:as well as the Midland Basin, the Delaware Basin, and the Central Basin Platform. We have historically been focused on the Midland Basin and more recently entered the Delaware Basin through an acquisition completedEagle Ford in February 2017.South Texas. Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. Our drilling activity is predominantly focused on the horizontal development of several prospective intervals in the Permian, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales.shales, and the Eagle Ford. We have assembled a multi-year inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and through acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps. Our production was approximately 78% oil
Financial and 22% natural gasOperational Highlights
For discussion of our significant financial and operational highlights for the year ended December 31, 2017. On December 31, 2017, our net acreage position2021, please see “Part 1. Items 1 and 2. Business and Properties — Overview — Major Developments in the Permian Basin was 57,481 net acres.2021”.
Significant accomplishmentsfor2017include:
Increased annual production in 2017 by 50% to 8,373 MBOE as compared to 2016;
Increased 2017 proved reserves by 50% to 137 MMBOE as compared to 2016;
Entered the Delaware Basin through an acquisition completed in February 2017, acquiring approximately 29,175 gross (16,688 net) acres;
In 2017, we transitioned from a two rig to a four rig horizontal drilling program.
Issued an additional $200 million aggregate principal amount of its 6.125% Senior Notes; and
Amended the borrowing base under our Credit Facility to $700 million with a current elected commitment level of $500 million, providing us with additional liquidity.
Operational Highlights
All of our producing properties are located in the Permian Basin. As a result of our acquisition and horizontal development efforts, our production grew 50% in 2017 compared to 2016, increasing to 8,373 MBOE from 5,573 MBOE. Our production in 2017 was approximately 78% oil and 22% natural gas.
In 2017, we transitioned from a two rig to four rig horizontal drilling program. For the year ended December 31, 2017, we drilled 49 gross (38.2 net) horizontal wells, completed 52 gross (41.4 net) horizontal wells and had four gross (2.0 net) horizontal wells awaiting completion.
Reserve Growth
As of December 31, 2017, our estimated net proved reserves increased 50% to 137.0 MMBOE compared to 91.6 MMBOE of estimated net proved reserves at year-end 2016. Our significant growth in proved reserves was primarily attributable to our horizontal development and acquisition efforts. Our proved reserves at year-end 2017 and 2016 were 78% oil and 22% natural gas for both periods.
Liquidity and Capital Resources
Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions, the sale of debt and equity securities, and asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties, in addition to refinancing of debt instruments.
|
| | |
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operation | |
In 2017, we issued an additional $200 million aggregate principal amount of our 6.125% Senior Notes to raise additional capital. In addition, we amended the borrowing base under our Credit Facility to $700 million with a current elected commitment level of $500 million, providing us with additional liquidity. We continue to evaluate other sources of capital to complement our cash flow from operations and other sources of capital as we pursue our long-term growth plans. See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s debt.
For the year ended December 31, 2017, cash and cash equivalents decreased $625.0 million to $28.0 million compared to $653.0 million at December 31, 2016.
Liquidity and cash flow
|
| | | | | | | | | | | |
| Twelve Months Ended December 31, |
(in thousands) | 2017 | | 2016 | | 2015 |
Net cash provided by operating activities | $ | 229,891 |
| | $ | 120,774 |
| | $ | 89,319 |
|
Net cash used in investing activities | (1,072,532 | ) | | (866,287 | ) | | (259,160 | ) |
Net cash provided by financing activities | 217,643 |
| | 1,397,282 |
| | 170,097 |
|
Net change in cash and cash equivalents | $ | (624,998 | ) | | $ | 651,769 |
| | $ | 256 |
|
Operating activities. For the year ended December 31, 2017, net cash provided by operating activities was $229.9 million, compared to $120.8 million for the same period in 2016. The change in operating activities was predominantly attributable to the following:
An increase in revenue;
A decrease in settlements of derivative contracts;
An increase in certain operating expenses related to acquired properties;
An increase in payments in cash-settled restricted stock unit (“RSU”) awards; and
A change related to the timing of working capital payments and receipts.
Production, realized prices, and operating expenses are discussed below in Results of Operations. See Notes 6 and 7 in the Footnotes to the Financial Statements for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation. See Note 3 in the Footnotes to the Financial Statements for more information on the Company’s acquisitions.
Investing activities. For the year ended December 31, 2017, net cash used in investing activities was $1,072.5 million compared to $866.3 million for the same period in 2016. The change in investing activities was primarily attributable to the following:
A $229.8 million increase in operational expenditures primarily due to our transition from a one-rig program in 2016 to a four-rig program in 2017. In August 2016, we transitioned from a one-rig program to a two-rig program. We transitioned from a two-rig program to a three-rig program in January 2017 and from a three-rig program to a four-rig program in July 2017; and
A $23.6 million decrease in acquisitions, net of proceeds from the sale of mineral interest and equipment.
Our investing activities, on a cash basis, include the following for the periods indicated (in thousands):
|
| | | | | | | | | | | | |
| | Twelve Months Ended December 31, |
| | 2017 | | 2016 | | $ Change |
Operational expenditures | | $ | 355,833 |
| | $ | 143,856 |
| | $ | 211,977 |
|
Seismic, leasehold and other | | 16,385 |
| | 13,640 |
| | 2,745 |
|
Capitalized general and administrative costs | | 17,016 |
| | 12,679 |
| | 4,337 |
|
Capitalized interest | | 30,605 |
| | 19,857 |
| | 10,748 |
|
Total capital expenditures(a) | | 419,839 |
| | 190,032 |
| | $ | 229,807 |
|
| | | | | | |
Acquisitions | | 718,456 |
| | 654,679 |
| | 63,777 |
|
Acquisition deposits | | (45,238 | ) | | 46,138 |
| | (91,376 | ) |
Proceeds from the sale of mineral interest and equipment | | (20,525 | ) | | (24,562 | ) | | 4,037 |
|
Total investing activities | | $ | 1,072,532 |
| | $ | 866,287 |
| | $ | 206,245 |
|
| |
(a) | On an accrual (GAAP) basis, which is the methodology used for establishing our annual capital budget, operational expenditures for the year ended December 31, 2017 were $392.7 million. Inclusive of capitalized general and administrative expenses and capitalized interest expenses, total capital expenditures were $463.2 million. |
|
| | |
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operation | |
General and administrative expenses and capitalized interest are discussed below in Results of Operations. See Notes 3 and 14 in the Footnotes to the Financial Statements for additional information on significant acquisitions and drilling rig leases.
Financing activities. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our Credit Facility, term debt and equity offerings. For the year ended December 31, 2017, net cash provided by financing activities was $217.6 million compared to cash provided by financing activities of $1,397.3 million during the same period of 2016. The change in net cash provided by financing activities was primarily attributable to the following:
A decrease in proceeds resulting from common stock offerings. In 2016, we raised $1,357.6 million through four common stock offerings as compared no common stock offerings in 2017; and
A $188.2 million decrease in borrowings on fixed rate debt. In 2016, we issued a $400 million aggregate principal amount of 6.125% Senior Notes, and in 2017, we issued an additional $200 million aggregate principal amount, including a premium issue price of 104.125%, of the 6.125% Senior Notes.
Net cash provided by financing activities includes the following for the periods indicated (in thousands):
|
| | | | | | | | | | | |
| Twelve Months Ended December 31, |
| 2017 | | 2016 | | $ Change |
Net borrowings on Credit Facility | $ | 25,000 |
| | $ | (40,000 | ) | | $ | 65,000 |
|
Net borrowings on term loans | — |
| | (300,000 | ) | | |
Issuance of 6.125% Senior Notes | 200,000 |
| | 400,000 |
| | (200,000 | ) |
Premium on the issuance of 6.125% Senior Notes | 8,250 |
| | — |
| | 8,250 |
|
Issuance of common stock | — |
| | 1,357,577 |
| | (1,357,577 | ) |
Payment of preferred stock dividends | (7,295 | ) | | (7,295 | ) | | — |
|
Payment of deferred financing costs | (7,194 | ) | | (10,793 | ) | | 3,599 |
|
Tax withholdings related to restricted stock units | (1,118 | ) | | (2,207 | ) | | 1,089 |
|
Net cash provided by financing activities | $ | 217,643 |
| | $ | 1,397,282 |
| | $ | (1,179,639 | ) |
See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s debt. See Note 10 in the Footnotes to the Financial Statements for additional information about the Company’s equity offerings and Series A 10% Cumulative Preferred Stock.
Credit Facility
On May 31, 2017, the Company entered into the Sixth Amended and Restated Credit Agreement to the Credit Facility with a maturity date of May 25, 2022. The total notional amount available under the Company’s Credit Facility is $2,000 million. Concurrent with the execution of the Sixth Amended and Restated Credit Agreement, the Credit Facility’s borrowing base increased to $650 million, but the Company elected an aggregate commitment amount of $500 million. On November 7, 2017, the Credit Facility’s borrowing base increased to $700 million with a reaffirmed commitment of $500 million, following the semi-annual review. As of December 31, 2017, the Credit Facility had a balance of $25 million outstanding.
For the year ended December 31, 2017, the Credit Facility had a weighted-average interest rate of 3.11%, calculated as the LIBOR plus a tiered rate ranging from 2.00% to 3.00%, which is determined based on utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.375% per annum, payable quarterly, on the unused portion of the borrowing base.
See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s Credit Facility.
6.125% Senior Notes
On October 3, 2016, the Company issued $400 million aggregate principal amount of 6.125% Senior Notes with a maturity date of October 1, 2024 and interest payable semi-annually beginning on April 1, 2017. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $391.3 million. The 6.125% Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries.
On May 19, 2017, the Company issued an additional $200 million aggregate principal amount of its 6.125% Senior Notes which with the existing $400 million aggregate principal amount of 6.125% Senior Notes are treated as a single class of notes under the indenture.
|
| | |
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operation | |
The net proceeds of the offering, including a premium issue price of 104.125% and after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $206.1 million.
See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s 6.125% Senior Notes.
10% Series A Cumulative Preferred Stock (“Preferred Stock”)
Holders of the Company’s Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10.0% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends are payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by our Board of Directors. Preferred Stock dividends were $7.3 million in 2017.
The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. On or after May 30, 2018, the Company may, at its option, redeem the Preferred Stock, in whole or in part, by paying $50.00 per share, plus any accrued and unpaid dividends to the redemption date.
On February 4, 2016, the Company exchanged a total of 120,000 shares of Preferred Stock for 719,000 shares of common stock. As of December 31, 2017, the Company had 1,458,948 shares of its Preferred Stock issued and outstanding.
See Note 10 in the Footnotes to the Financial Statements for additional information about the Company’s Preferred Stock.
2018Capital Planand Outlook
Our operational capital budget for 2018 has been established in the range of $500 to $540 million on an accrual, or GAAP, basis, inclusive of a planned transition from a four rig program that commenced in July 2017 to a five rig program by mid-February 2018.
As part of our 2018 operated horizontal drilling program, we expect to place 43 to 46 net horizontal wells on production with lateral lengths ranging from 5,000’ to 10,000’.
In addition to the operational capital expenditures budget, which includes well costs, facilities and infrastructure capital, and surface land purchases, we budgeted an estimated $23 to $28 million for capitalized general and administrative expenses on an accrual, or GAAP, basis.
Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop our reserves of oil and natural gas. We believe the long-term outlook for our business is favorable due to our resource base, low cost structure, financial strength, risk management, including commodity hedging strategy, and disciplined investment of capital. We monitor current and expected market conditions, including the commodity price environment, and our liquidity needs and may adjust our capital investment plan accordingly.
Contractual Obligations
The following table includes the Company’s current contractual obligations and purchase commitments (in thousands):
|
| | | | | | | | | | | | | | | | | | | | |
| | Payments due by Period |
| | Total | | < 1 Year | | Years 2 - 3 | | Years 4 - 5 | | >5 Years |
6.125% Senior Notes (a) | | $ | 600,000 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 600,000 |
|
Credit Facility (b) | | 25,000 |
| | — |
| | — |
| | 25,000 |
| | — |
|
Interest expense and other fees related to debt commitments (c) | | 262,192 |
| | 39,958 |
| | 79,915 |
| | 78,006 |
| | 64,313 |
|
Drilling rig leases (d) | | 61,732 |
| | 29,482 |
| | 31,602 |
| | 648 |
| | — |
|
Office space lease and other commitments | | 14,858 |
| | 3,935 |
| | 7,543 |
| | 3,380 |
| | — |
|
Asset retirement obligations (e) | | 6,020 |
| | 1,295 |
| | — |
| | — |
| | 4,725 |
|
Total contractual obligations | | $ | 969,802 |
| | $ | 74,670 |
| | $ | 119,060 |
| | $ | 107,034 |
| | $ | 669,038 |
|
| |
(a) | Includes the outstanding principal amount only. The 6.125% Senior Notes have a maturity date of October 1, 2024. See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s 6.125% Senior Notes. |
| |
(b) | As of December 31, 2017, the Credit Facility had a $25 million balance outstanding. We cannot predict the timing of future borrowings and repayments. The Credit Facility has a maturity date of May 25, 2022. See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s Credit Facility. |
|
| | |
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operation | |
| |
(c) | Includes estimated cash payments on the 6.125% Senior Notes and Credit Facility and the minimum amount of commitment fees due on the Credit Facility.
|
| |
(d) | Drilling rig leases represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on December 31, 2017. The value in the table represents the gross amount that we are committed to pay. However, we will record our proportionate share based on our working interest in our consolidated financial statements as incurred. See Note 14 in the Footnotes to the Financial Statements for additional information related to the Company’s drilling rig leases. |
| |
(e) | Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 12 in the Footnotes to the Financial Statements for additional information. |
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| | |
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operation | |
Results of Operations
The following table sets forth certain operating information with respect to the Company’s oil and natural gas operations for the periods indicated:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2021 | | 2020 | | $ Change | | % Change |
Total production | | | | | | | | |
Oil (MBbls) | | | | | | | | |
Permian | | 14,475 | | 14,113 | | 362 | | | 3 | % |
Eagle Ford | | 7,749 | | 9,430 | | (1,681) | | | (18 | %) |
Total oil | | 22,224 | | 23,543 | | (1,319) | | | (6 | %) |
| | | | | | | | |
Natural gas (MMcf) | | | | | | | | |
Permian | | 29,682 | | 32,087 | | (2,405) | | | (7 | %) |
Eagle Ford | | 7,704 | | 8,714 | | (1,010) | | | (12 | %) |
Total natural gas | | 37,386 | | 40,801 | | (3,415) | | | (8 | %) |
| | | | | | | | |
NGLs (MBbls) | | | | | | | | |
Permian | | 5,155 | | 5,390 | | (235) | | | (4 | %) |
Eagle Ford | | 1,284 | | 1,460 | | (176) | | | (12 | %) |
Total NGLs | | 6,439 | | 6,850 | | (411) | | | (6 | %) |
| | | | | | | | |
Total production (MBoe) | | | | | | | | |
Permian | | 24,577 | | 24,851 | | (274) | | | (1 | %) |
Eagle Ford | | 10,317 | | 12,342 | | (2,025) | | | (16 | %) |
Total barrels of oil equivalent | | 34,894 | | 37,193 | | (2,299) | | | (6 | %) |
| | | | | | | | |
Total daily production (Boe/d) | | 95,599 | | 101,620 | | (6,021) | | | (6 | %) |
Oil as % of total daily production | | 64 | % | | 63 | % | | | | 1 | % |
| | | | | | | | |
Benchmark prices(1) | | | | | | | | |
WTI (per Bbl) | | $67.94 | | $39.38 | | $28.56 | | | 73 | % |
Henry Hub (per Mcf) | | 3.72 | | 2.13 | | 1.59 | | | 75 | % |
| | | | | | | | |
Average realized sales price (excluding impact of derivative settlements) | | | | | | | | |
Oil (per Bbl) | | | | | | | | |
Permian | | $68.20 | | $37.23 | | $30.97 | | | 83 | % |
Eagle Ford | | 68.27 | | 34.49 | | 33.78 | | | 98 | % |
Total oil | | 68.22 | | 36.13 | | 32.09 | | | 89 | % |
| | | | | | | | |
Natural gas (per Mcf) | | | | | | | | |
Permian | | 3.69 | | 1.05 | | 2.64 | | | 251 | % |
Eagle Ford | | 4.13 | | 2.07 | | 2.06 | | | 100 | % |
Total natural gas | | 3.78 | | 1.27 | | 2.51 | | | 198 | % |
| | | | | | | | |
NGL (per Bbl) | | | | | | | | |
Permian | | 30.60 | | 11.91 | | 18.69 | | | 157 | % |
Eagle Ford | | 28.12 | | 11.71 | | 16.41 | | | 140 | % |
Total NGL | | 30.11 | | 11.87 | | 18.24 | | | 154 | % |
| | | | | | | | |
Total average realized sales price (per Boe) | | | | | | | | |
Permian | | 51.05 | | 25.09 | | 25.96 | | | 103 | % |
Eagle Ford | | 57.86 | | 29.20 | | 28.66 | | | 98 | % |
Total average realized sales price | | $53.06 | | $26.45 | | $26.61 | | | 101 | % |
| | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Twelve Months Ended December 31, |
| | 2017 | | 2016 | | Change | | % Change | | 2015 | | Change | | % Change |
Net production: | | | | | | | | | | | | | | |
Oil (MBbls) | | 6,557 |
| | 4,280 |
| | 2,277 |
| | 53 | % | | 2,789 |
| | 1,491 |
| | 53 | % |
Natural gas (MMcf) | | 10,896 |
| | 7,758 |
| | 3,138 |
| | 40 | % | | 4,312 |
| | 3,446 |
| | 80 | % |
Total (MBOE) | | 8,373 |
| | 5,573 |
| | 2,800 |
| | 50 | % | | 3,508 |
| | 2,065 |
| | 59 | % |
Average daily production (BOE/d) | | 22,940 |
| | 15,227 |
| | 7,713 |
| | 50 | % | | 9,610 |
| | (9,595 | ) | | (100 | )% |
% oil (BOE basis) | | 78 | % | | 77 | % | | | | | | 80 | % | | | | |
Average realized sales price (excluding impact of cash settled derivatives): | | | | | | | | | | | | | | |
Oil (Bbl) | | $ | 49.16 |
| | $ | 41.51 |
| | $ | 7.65 |
| | 18 | % | | $ | 44.88 |
| | $ | (3.37 | ) | | (8 | )% |
Natural gas (Mcf) | | 4.05 |
| | 2.99 |
| | 1.06 |
| | 35 | % | | 2.86 |
| | 0.13 |
| | 5 | % |
Total (BOE) | | $ | 43.77 |
| | $ | 36.04 |
| | $ | 7.73 |
| | 21 | % | | $ | 39.20 |
| | $ | (3.16 | ) | | (8 | )% |
Average realized sales price (including impact of cash settled derivatives): | | | | | | | | | | | | | | |
Oil (Bbl) | | $ | 47.78 |
| | $ | 45.67 |
| | $ | 2.11 |
| | 5 | % | | $ | 56.82 |
| | $ | (11.15 | ) | | (20 | )% |
Natural gas (Mcf) | | 4.10 |
| | 3.00 |
| | 1.10 |
| | 37 | % | | 3.26 |
| | (0.26 | ) | | (8 | )% |
Total (BOE) | | $ | 42.76 |
| | $ | 39.25 |
| | $ | 3.51 |
| | 9 | % | | $ | 49.18 |
| | $ | (9.93 | ) | | (20 | )% |
Oil and natural gas revenues (in thousands): | | | | | | | | | | | | | | |
Oil revenue | | $ | 322,374 |
| | $ | 177,652 |
| | $ | 144,722 |
| | 81 | % | | $ | 125,166 |
| | $ | 52,486 |
| | 42 | % |
Natural gas revenue | | 44,100 |
| | 23,199 |
| | 20,901 |
| | 90 | % | | 12,346 |
| | $ | 10,853 |
| | 88 | % |
Total | | $ | 366,474 |
| | $ | 200,851 |
| | $ | 165,623 |
| | 82 | % | | $ | 137,512 |
| | $ | 63,339 |
| | 46 | % |
Additional per BOE data: | | | | | | | | | | | | | | |
Sales price (a) | | $ | 43.77 |
| | $ | 36.04 |
| | $ | 7.73 |
| | 21 | % | | $ | 39.20 |
| | $ | (3.16 | ) | | (8 | )% |
Lease operating expense (b) | | 5.46 |
| | 6.56 |
| | (1.10 | ) | | (17 | )% | | 7.48 |
| | (0.92 | ) | | (12 | )% |
Gathering and treating expense | | 0.50 |
| | 0.32 |
| | 0.18 |
| | 56 | % | | 0.23 |
| | 0.09 |
| | 39 | % |
Production taxes | | 2.67 |
| | 2.13 |
| | 0.54 |
| | 25 | % | | 2.79 |
| | (0.66 | ) | | (24 | )% |
Operating margin | | $ | 35.14 |
| | $ | 27.03 |
| | $ | 8.11 |
| | 30 | % | | $ | 28.70 |
| | $ | (1.67 | ) | | (6 | )% |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2021 | | 2020 | | $ Change | | % Change |
Revenues (in thousands) | | | | | | | | |
Oil | | | | | | | | |
Permian | | $987,195 | | $525,412 | | $461,783 | | | 88 | % |
Eagle Ford | | 529,030 | | 325,255 | | 203,775 | | | 63 | % |
Total oil | | 1,516,225 | | 850,667 | | 665,558 | | | 78 | % |
| | | | | | | | |
Natural gas | | | | | | | | |
Permian | | 109,640 | | 33,815 | | 75,825 | | | 224 | % |
Eagle Ford | | 31,853 | | 18,051 | | 13,802 | | | 76 | % |
Total natural gas | | 141,493 | | 51,866 | | 89,627 | | | 173 | % |
| | | | | | | | |
NGLs | | | | | | | | |
Permian | | 157,757 | | 64,201 | | 93,556 | | | 146 | % |
Eagle Ford | | 36,104 | | 17,094 | | 19,010 | | | 111 | % |
Total NGLs | | 193,861 | | 81,295 | | 112,566 | | | 138 | % |
| | | | | | | | |
Total revenues | | | | | | | | |
Permian | | 1,254,592 | | 623,428 | | 631,164 | | | 101 | % |
Eagle Ford | | 596,987 | | 360,400 | | 236,587 | | | 66 | % |
Total revenues | | $1,851,579 | | $983,828 | | $867,751 | | | 88 | % |
| | | | | | | | |
Additional per Boe data | | | | | | | | |
Lease operating expense | | | | | | | | |
Permian | | $5.27 | | $4.71 | | $0.56 | | | 12 | % |
Eagle Ford | | 7.13 | | 6.25 | | 0.88 | | | 14 | % |
Total lease operating expense | | $5.82 | | $5.22 | | $0.60 | | | 11 | % |
| | | | | | | | |
Production and ad valorem taxes | | | | | | | | |
Permian | | $2.75 | | $1.59 | | $1.16 | | | 73 | % |
Eagle Ford | | 3.16 | | 1.87 | | 1.29 | | | 69 | % |
Total production and ad valorem taxes | | $2.87 | | $1.68 | | $1.19 | | | 71 | % |
| | | | | | | | |
Gathering, transportation and processing | | | | | | | | |
Permian | | $2.54 | | $2.29 | | $0.25 | | | 11 | % |
Eagle Ford | | 1.80 | | 1.66 | | 0.14 | | | 8 | % |
Total gathering, transportation and processing | | $2.32 | | $2.08 | | $0.24 | | | 12 | % |
| | |
(a) | Excludes the impact of cash settled derivatives. |
| |
(b) | Excludes gathering and treating expense. |
(1) Reflects calendar average daily spot market prices.
Revenues
The following tables are intended to reconciletable reconciles the changechanges in oil, natural gas, NGLs, and total revenue for the respective periodsperiod presented by reflecting the effect of changes in volume and in the underlying commodity prices. |
| | | | | | | | | | | | |
(in thousands) | | Oil | | Natural Gas | | Total |
Revenues for the year ended December 31, 2014 | | $ | 139,374 |
| | $ | 12,488 |
| | $ | 151,862 |
|
Volume increase | | 90,398 |
| | 11,774 |
| | 102,172 |
|
Price decrease | | (104,606 | ) | | (11,916 | ) | | (116,522 | ) |
Net decrease | | (14,208 | ) | | (142 | ) | | (14,350 | ) |
Revenues for the year ended December 31, 2015 | | $ | 125,166 |
| | $ | 12,346 |
| | $ | 137,512 |
|
Volume increase | | 66,916 |
| | 9,856 |
| | 76,772 |
|
Price increase (decrease) | | (14,430 | ) | | 997 |
| | (13,433 | ) |
Net increase | | 52,486 |
| | 10,853 |
| | 63,339 |
|
Revenues for the year ended December 31, 2016 | | $ | 177,652 |
| | $ | 23,199 |
| | $ | 200,851 |
|
Volume increase | | 94,518 |
| | 9,383 |
| | 103,901 |
|
Price increase | | 50,204 |
| | 11,518 |
| | 61,722 |
|
Net increase | | 144,722 |
| | 20,901 |
| | 165,623 |
|
Revenues for the year ended December 31, 2017 | | $ | 322,374 |
| | $ | 44,100 |
| | $ | 366,474 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Oil | | Natural Gas | | NGLs | | Total |
| | (In thousands) |
Revenues for the year ended December 31, 2020 (1) | | $850,667 | | $51,866 | | $81,295 | | $983,828 | |
Volume increase (decrease) | | (47,659) | | (4,342) | | (4,878) | | (56,879) | |
Price increase (decrease) | | 713,217 | | 93,969 | | 117,444 | | 924,630 | |
Net increase (decrease) | | 665,558 | | 89,627 | | 112,566 | | 867,751 | |
Revenues for the year ended December 31, 2021 (1) | | $1,516,225 | | $141,493 | | $193,861 | | $1,851,579 | |
| | | | | | | | |
Percent of total revenues | | 82 | % | | 8 | % | | 10 | % | | |
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Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operation | |
Commodity Prices
The prices for oil and natural gas remain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and actions by OPEC and other countries and government actions. Prices(1) Excludes sales of oil and natural gas will affect the following aspects ofpurchased from third parties and sold to our business:customers.
our revenues, cash flows and earnings;
the amount of oil and natural gas that we are economically able to produce;
our ability to attract capital to finance our operations and cost of the capital;
the amount we are allowed to borrow under our Credit Facility; and
the value of our oil and natural gas properties.
For the year ended December 31, 2017, the average NYMEX price for a barrel of oil was $50.80 per Bbl compared to $43.39 per Bbl for the same period of 2016. The NYMEX price for a barrel of oil ranged from a low of $42.53 per Bbl to a high of $60.42 per BblRevenues for the year ended December 31, 2017.
For the year ended December 31, 2017, the average NYMEX price for natural gas was $3.02 per MMBtu compared to $2.55 per MMBtu for the same period in 2016. The NYMEX price for natural gas ranged from a low2021, of $2.56 per MMBtu to a high of $3.42 per MMBtu for the year ended December 31, 2017.
Oil revenue
For the year ended December 31, 2017, oil revenues of $322 million$1.9 billion increased $145$867.8 million, or 81%88%, compared to revenues of $178$983.8 million for the year ended December 31, 2016.2020. The increase in oil revenue was primarily attributable to a 53% increase in production and an 18%101% increase in the average realized sales price which rose to $49.16$53.06 per BblBoe from $41.51$26.45 per Bbl.Boe as well as revenue attributable to wells that were acquired in the Primexx Acquisition. The increase in the average realized sales price was partially offset by a 6% decrease in production, which was comprisedprimarily due to the divestitures that occurred during 2021 as well as normal production decline, partially offset by production resulting from our developmental activities during the year as well as production from the properties acquired in the Primexx Acquisition.
Operating Expenses
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | | | Per | | | | Per | | Total Change | | Boe Change |
| | 2021 | | Boe | | 2020 | | Boe | | $ | | % | | $ | | % |
| | (In thousands, except per Boe and % amounts) |
Lease operating | | $203,141 | | | $5.82 | | | $194,101 | | | $5.22 | | | $9,040 | | | 5 | % | | $0.60 | | | 11 | % |
Production and ad valorem taxes | | 100,160 | | | 2.87 | | | 62,638 | | | 1.68 | | | 37,522 | | | 60 | % | | 1.19 | | | 71 | % |
Gathering, transportation and processing | | 80,970 | | | 2.32 | | | 77,309 | | | 2.08 | | | 3,661 | | | 5 | % | | 0.24 | | | 12 | % |
Depreciation, depletion and amortization | | 356,556 | | | 10.22 | | | 480,631 | | | 12.92 | | | (124,075) | | | (26 | %) | | (2.70) | | | (21 | %) |
General and administrative | | 50,483 | | | 1.45 | | | 37,187 | | | 1.00 | | | 13,296 | | | 36 | % | | 0.45 | | | 45 | % |
Impairment of evaluated oil and gas properties | | — | | | — | | | 2,547,241 | | | 68.48 | | | (2,547,241) | | | (100 | %) | | (68.48) | | | (100 | %) |
Merger, integration and transaction | | 14,289 | | | 0.41 | | | 28,482 | | | 0.77 | | | (14,193) | | | (50 | %) | | (0.36) | | | (47 | %) |
Lease Operating Expenses. Lease operating expenses for the year ended December 31, 2021 increased by 5% to $203.1 million compared to $194.1 million for the same period of 2,125 MBbls2020, primarily due to operating expenses attributable to wells placed onthat were acquired in the Primexx Acquisition, partially offset by a reduction in certain operating expenses such as repairs and maintenance and equipment rentals. Lease operating expense per Boe for the year ended December 31, 2021 increased to $5.82 compared to $5.22 for the same period of 2020 primarily due to the wells that were acquired in the Primexx Acquisition, as discussed above, higher costs driven by the recent increase in inflation, as well as the distribution of fixed costs spread over lower production as a result of our horizontal drilling programvolumes.
Production and 1,191 MBbls attributable to producing wells added from our acquired properties. Offsetting these increases were normal and expected declines from our existing wells.
Ad Valorem Taxes.For the year ended December 31, 2016, oil revenues of $1782021, production and ad valorem taxes increased 60% to $100.2 million increased $52.5 million, or 42%, compared to revenues of $125$62.6 million for the same period of 2015. The2020, which is primarily related to an 88% increase in oil revenue was primarily attributable to a 53% increase intotal revenues which increased production offset by an 8% decrease in the average realized sales price, which fell to $41.51 per Bbl from $44.88 per Bbl.taxes. The increase in production was comprisedimpact of 1,182 MBbls attributable to wells placed on production as a result of our horizontal drilling program and 547 MBbls attributable to producing wells added from our acquired properties. Offsetting these increases were normal and expected declines from our existing wells.
Natural gas revenue (including NGLs)
Natural gas revenues of $44.1 million increased $20.9 million, or 90%, during the year ended December 31, 2017 compared to $23.2 million for the year ended December 31, 2016. The increase primarily relates to a 40% increase in natural gas volumes and a 35% increase in the average price realized, which rose to $4.05 per Mcf from $2.99 per Mcf, reflecting increases in both natural gas and natural gas liquids prices. The increase in production was comprised of 1,969 MMcf attributable to wells placed on production as a result of our horizontal drilling program and 1,375 MMcf attributable to producing wells added from our acquired properties. Offsetting these increases were normal and expected declines from our existing wells.
Natural gas revenues of $23.2 million increased $10.9 million, or 88%, during the year ended December 31, 2016 compared to $12.3 million for the same period of 2015. The increase primarily relates to an 80% increase in natural gas volumes and a 5% increase in the average price realized, which rose to $2.99 per Mcf from $2.86 per Mcf, reflecting increases in both natural gas and natural gas liquids prices. The increase in production was comprised of 1,387 MMcf attributable to wells placed on production as a result of our horizontal drilling program and 1,025 MMcf attributable to producing wells added from our acquired properties. In addition, the increase in production taxes described above was also attributable to the increase in the percentage of natural gas produced in our production stream.
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Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operation | |
Operating Expenses
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Twelve Months Ended December 31, |
| | | | Per | | | | Per | | Total Change | | BOE Change |
(in thousands, except per unit amounts) | | 2017 | | BOE | | 2016 | | BOE | | $ | | % | | $ | | % |
Lease operating expenses | | $ | 49,907 |
| | $ | 5.96 |
| | $ | 38,353 |
| | $ | 6.88 |
| | $ | 11,554 |
| | 30 | % | | $ | (0.92 | ) | | (13 | )% |
Production taxes | | 22,396 |
| | $ | 2.67 |
| | 11,870 |
| | $ | 2.13 |
| | 10,526 |
| | 89 | % | | 0.54 |
| | 25 | % |
Depreciation, depletion and amortization | | 115,714 |
| | $ | 13.82 |
| | 71,369 |
| | $ | 12.81 |
| | 44,345 |
| | 62 | % | | 1.01 |
| | 8 | % |
General and administrative | | 27,067 |
| | $ | 3.23 |
| | 26,317 |
| | $ | 4.72 |
| | 750 |
| | 3 | % | | (1.49 | ) | | (32 | )% |
Settled share-based awards | | 6,351 |
| | nm |
| | — |
| | nm |
| | 6,351 |
| | nm |
| | nm |
| | nm |
|
Accretion expense | | 677 |
| | $ | 0.08 |
| | 958 |
| | $ | 0.17 |
| | (281 | ) | | (29 | )% | | (0.09 | ) | | (53 | )% |
Write-down of oil and natural gas properties | | — |
| | nm |
| | 95,788 |
| | nm |
| | (95,788 | ) | | nm |
| | nm |
| | nm |
|
Acquisition expense | | 2,916 |
| | nm |
| | 3,673 |
| | nm |
| | (757 | ) | | nm |
| | nm |
| | nm |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Twelve Months Ended December 31, |
| | | | Per | | | | Per | | Total Change | | BOE Change |
(in thousands, except per unit amounts) | | 2016 | | BOE | | 2015 | | BOE | | $ | | % | | $ | | % |
Lease operating expenses | | $ | 38,353 |
| | $ | 6.88 |
| | $ | 27,036 |
| | $ | 7.71 |
| | $ | 11,317 |
| | 42 | % | | $ | (0.83 | ) | | (11 | )% |
Production taxes | | 11,870 |
| | $ | 2.13 |
| | 9,793 |
| | $ | 2.79 |
| | 2,077 |
| | 21 | % | | (0.66 | ) | | (24 | )% |
Depreciation, depletion and amortization | | 71,369 |
| | $ | 12.81 |
| | 69,249 |
| | $ | 19.74 |
| | 2,120 |
| | 3 | % | | (6.93 | ) | | (35 | )% |
General and administrative | | 26,317 |
| | $ | 4.72 |
| | 28,347 |
| | $ | 8.08 |
| | (2,030 | ) | | (7 | )% | | (3.36 | ) | | (42 | )% |
Accretion expense | | 958 |
| | $ | 0.17 |
| | 660 |
| | $ | 0.19 |
| | 298 |
| | 45 | % | | (0.02 | ) | | (11 | )% |
Write-down of oil and natural gas properties | | 95,788 |
| | nm |
| | 208,435 |
| | nm |
| | (112,647 | ) | | nm |
| | nm |
| | nm |
|
Rig termination fee | | — |
| | nm |
| | 3,075 |
| | nm |
| | (3,075 | ) | | nm |
| | nm |
| | nm |
|
Acquisition expense | | 3,673 |
| | nm |
| | 27 |
| | nm |
| | 3,646 |
| | nm |
| | nm |
| | nm |
|
nm = not meaningful
Lease operating expenses. These are daily costs incurred to extract oil and natural gas and maintain our producing properties. Such costs also include maintenance, repairs, gas treating fees, salt water disposal, insurance and workover expenses related to our oil and natural gas properties.
LOE for the year ended December 31, 2017 increased by 30% to $49.9 million compared to $38.4 million for the same period of 2016. Contributing to the increase was $11.0 million related to oil and natural gas properties acquired during 2016 and 2017 (see Note 3 in the Footnotes to the Financial Statements for information about the Company’s acquisitions). LOE per BOE for the year ended December 31, 2017 decreased to $5.96 per BOE compared to $6.88 per BOE for the same period of 2016, which was primarily attributable to higher production volumes resulting from an increased number of producing wells from our horizontal drilling program and acquisitions as discussed above.
LOE for the year ended December 31, 2016 increased by 42% to $38.4 million compared to $27.0 million for the same period of 2015. Contributing to the increase for the current period was $7.3 million related to oil and natural gas properties acquired during 2016 (see Note 3 in the Footnotes to the Financial Statements for information about the Company’s acquisitions). Excluding LOE related to these acquired properties, LOE increased by $4.0 million, or 15%, compared to the same period of 2015. LOE per BOE for the year ended December 31, 2016 decreased to $6.88 per BOE compared to $7.71 per BOE for the same period of 2015, which was primarily attributable to higher production volumes offset by an increase in cost from workover activity on our legacy properties. The increase in production was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions as discussed above.
Production taxes. Production taxes include severance and ad valorem taxes. In general, production taxes are directly related to commodity price changes; however, severance taxes are based upon current year commodity prices, whereas ad valorem taxes are based upon prior year commodity prices. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. In the counties where our production is located, we are also subject to ad valorem taxes, which are generally based on the taxing jurisdictions’ valuation of our oil and gas properties.
For the year ended December 31, 2017, production taxes increased 89%, or $10.5 million, to $22.4 million compared to $11.9 million for the same period of 2016. The increase was primarily due to an increase in severance taxes, which was attributable to the increase in revenue. The increase was also attributable to an increase in ad valorem taxes due to a higher valuation of our oil and gas properties by
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Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operation | |
the taxing jurisdictions due to an increased number of producing wells as a result of our horizontal drilling program and acquisitions. On a per BOE basis, production taxes for the year ended December 31, 2017 increased by 25% compared to the same period of 2016.
For the year ended December 31, 2016, production taxes increased 21%, or $2.1 million, to $11.9 million compared to $9.8 million for the same period of 2015. The increase was primarily due to an increase in severance taxes, which was attributable to the increase in revenue. The increase waspartially offset by a decrease in ad valorem taxes attributabledue to lower property tax valuations for 2021 as a result of lower valuationcommodity prices during 2020. Production and ad valorem taxes as a percentage of our oil and gas properties by the taxing jurisdictions. On a per BOE basis, production taxestotal revenues decreased to 5.4% for the year ended December 31, 2016 decreased by 24%2021, as compared to 6.4% of total revenues for the same period of 2015.2020, primarily due to lower property tax valuations for 2021 as discussed above.
Depreciation, depletionGathering, Transportation and amortization (“DD&A”). Under the full cost accounting method, we capitalizeProcessing Expenses. Gathering, transportation and processing costs within a cost center and then systematically expense those costs on a units-of-production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unevaluated properties, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years.
Forfor the year ended December 31, 2017, DD&A2021 increased 62%by 5% to $115.7 million from $71.4$81.0 million compared to the same period of 2016. The increase is primarily attributable to a 50% increase in production and an 8% increase in our per BOE DD&A rate.The increase in production was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions. For the year ended December 31, 2017, DD&A on a per unit basis increased to $13.82 per BOE compared to $12.81 per BOE$77.3 million for the same period of 2016. The increase is attributable to our increase in our depreciable base and assumed future development costs2020, which was primarily related to undeveloped proved reserves relativenew oil transportation agreements that were in place for the full year of 2021 as compared to a partial year in 2020, partially offset by a 6% decrease in production volumes between the two periods as discussed above.
Depreciation, Depletion and Amortization (“DD&A”). The following table sets forth the components of our increased estimated proved reserves as a result of additions made through our horizontal drilling effortsdepreciation, depletion and acquisitions.amortization for the periods indicated:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, | | |
| | 2021 | | 2020 | | | | |
| | Amount | | Per Boe | | Amount | | Per Boe | | | | | | | | |
| | (In thousands, except per Boe) | | | | | | | | |
DD&A of evaluated oil and gas properties | | $347,199 | | | $9.95 | | | $471,074 | | | $12.66 | | | | | | | | | |
Depreciation of other property and equipment | | 1,950 | | | 0.06 | | | 3,548 | | | 0.10 | | | | | | | | | |
Amortization of other assets | | 3,664 | | | 0.10 | | | 2,686 | | | 0.07 | | | | | | | | | |
Accretion of asset retirement obligations | | 3,743 | | | 0.11 | | | 3,323 | | | 0.09 | | | | | | | | | |
DD&A | | $356,556 | | | $10.22 | | | $480,631 | | | $12.92 | | | | | | | | | |
| | | | | | | | | | | | | | | | |
For the year ended December 31, 2016,2021, DD&A increased 3%decreased to $71.4$356.6 million from $69.2$480.6 million compared to the same period of 2015. The increase is primarily attributable to a 59% increase in production, offset by a 35% decrease in our per BOE DD&A rate. The increase in production was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions. For the year ended December 31, 2016, DD&A on a per unit basis decreased to $12.81 per BOE compared to $19.74 per BOE for the same period of 2015.2020. The decrease is attributable to our increased estimated proved reserves relative to our depreciable basein DD&A was primarily the result of the impairments of evaluated oil and assumed future development costs related to undeveloped proved reservesgas properties that were recognized during 2020 as well as a resultproduction decrease of additions made through our horizontal drilling efforts and acquisitions, offset by the write-down of oil and natural gas properties in the first half of 2016.6% as discussed above.
General and administrative, netAdministrative, Net of amounts capitalizedAmounts Capitalized (“G&A”). These are costs incurred for overhead, including payroll and benefits for our corporate staff, severance and early retirement expenses, costs of maintaining offices, managing our production and development operations, franchise taxes, depreciation of corporate level assets, public company costs, vesting of equity and liability awards under share-based compensation plans and related mark-to-market valuation adjustments over time, fees for audit and other professional services, and legal compliance.
G&A for the year ended December 31, 20172021 increased to $27.1$50.5 million compared to $26.3$37.2 million for the same period of 2016. G&A expenses for2020, primarily due to an increase in the fair value of Cash-Settled RSU Awards and Cash SARs as a result of the significant increase in our stock price between the two periods indicated include the following (in thousands):as well as higher compensation costs.
|
| | | | | | | | | | | | | | | |
| | Twelve Months Ended December 31, |
| | 2017 | | 2016 | | $ Change | | % Change |
Recurring expenses | | | | | | | | |
G&A | | $ | 21,554 |
| | $ | 16,477 |
| | $ | 5,077 |
| | 31 | % |
Share-based compensation | | 4,287 |
| | 2,735 |
| | 1,552 |
| | 57 | % |
Fair value adjustments of cash-settled RSU awards | | 701 |
| | 6,881 |
| | (6,180 | ) | | (90 | )% |
Non-recurring expenses | | | | | | | | |
Early retirement expenses | | 444 |
| | — |
| | 444 |
| | 100 | % |
Early retirement expenses related to share-based compensation | | 81 |
| | — |
| | 81 |
| | 100 | % |
Expense related to a threatened proxy contest | | — |
| | 224 |
| | (224 | ) | | (100 | )% |
Total G&A expenses | | $ | 27,067 |
| | $ | 26,317 |
| | $ | 750 |
| | 3 | % |
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Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operation | |
G&AImpairment of Evaluated Oil and Gas Properties. We did not recognize an impairment of evaluated oil and gas properties for the year ended December 31, 2016 decreased to $26.3 million compared to $28.3 million for the same period2021. Impairments of 2015. G&A expenses for the periods indicated include the following (in thousands):
|
| | | | | | | | | | | | | | | |
| | Twelve Months Ended December 31, |
| | 2016 | | 2015 | | $ Change | | % Change |
Recurring expenses | | | | | | | | |
G&A | | $ | 16,477 |
| | $ | 15,086 |
| | $ | 1,391 |
| | 9 | % |
Share-based compensation | | 2,735 |
| | 2,068 |
| | 667 |
| | 32 | % |
Fair value adjustments of cash-settled RSU awards | | 6,881 |
| | 6,084 |
| | 797 |
| | 13 | % |
Non-recurring expenses | | | | | | | | |
Early retirement expenses | | — |
| | 3,553 |
| | (3,553 | ) | | (100 | )% |
Early retirement expenses related to share-based compensation | | — |
| | 1,115 |
| | (1,115 | ) | | (100 | )% |
Expense related to a threatened proxy contest | | 224 |
| | 441 |
| | (217 | ) | | (49 | )% |
Total G&A expenses | | $ | 26,317 |
| | $ | 28,347 |
| | $ | (2,030 | ) | | (7 | )% |
Settled share-based awards. In June 2017, the Company settled the outstanding share-based award agreementsevaluated oil and gas properties of its former Chief Executive Officer, resulting in $6.4 million recorded on the Consolidated Statements of Operations as Settled share-based awards.
Accretion expense. The Company is required to record the estimated fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated ARO costs. Interest is accreted on the present value of the ARO and reported as accretion expense within operating expenses in the Consolidated Statements of Operations.
Accretion expense related to our ARO decreased 29%$2.5 billion were recognized for the year ended December 31, 20172020, primarily due to declines in the 12-Month Average Realized Price of crude oil. See “Note 5 - Property and Equipment, Net” of the Notes to our Consolidated Financial Statements for further discussion.
Merger, Integration and Transaction Expenses. For the year ended December 31, 2021, we incurred merger, integration and transaction expenses of $14.3 million, which were associated with the Primexx Acquisition, as compared to the same period of 2016. Accretion expense generally correlates with the Company’s ARO,$28.5 million for 2020, which was $6.0 million at December 31, 2017 versus $6.7 million at December 31, 2016. See Note 12 in the Footnoteswere related to the Carrizo Acquisition. See “Note 4 – Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for additional information regarding the Company’s ARO.
Accretion expense related to our ARO increased 45% forPrimexx Acquisition and the year ended December 31, 2016 compared to the same period of 2015. Accretion expense generally correlates with the Company’s ARO, which was $6.7 million at December 31, 2016 versus $5.1 million at December 31, 2015. See Note 12 in the Footnotes to the Financial Statements for additional information regarding the Company’s ARO.
Write-down of oil and natural gas properties. Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full cost ceiling amount). These rules require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling.
For the year ended December 31, 2017, the Company recognized no write-down of oil and natural gas properties as a result of the ceiling test limitation. For the year ended December 31, 2016, the Company recognized a write-down of oil and natural gas properties of $95.8 million as a result of the ceiling test limitation, primarily driven by a 15% decrease in the 12-month average realized price of oil from $50.16 per barrel as of December 31, 2015 to $42.75 per barrel as of December 31, 2016. If commodity prices were to decline, we could incur additional ceiling test write-downs in the future. See Notes 2 and 13 in the Footnotes to the Financial Statements for additional information.
Rig termination fee. For the year ended December 31, 2015, the Company recognized $3.1 million in expense related to the early termination of the contract for its vertical rig. See Note 14 in the Footnotes to the Financial Statements for additional information.
Acquisition expense. Acquisition expense decreased $0.8 million for the year ended December 31, 2017 compared to the same period of 2016 and increased $3.6 million for the year ended December 31, 2016 compared to the same period of 2015. Acquisition expense for all periods was related to costs with respect to our acquisition efforts in the Permian Basin. See Note 2 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions.
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Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operation | |
Carrizo Acquisition.
Other Income and Expenses and Preferred Stock Dividends
|
| | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
(in thousands) | | 2017 | | 2016 | | $ Change | | % Change |
Interest expense, net of capitalized amounts | | $ | 2,159 |
| | $ | 11,871 |
| | $ | (9,712 | ) | | (82 | )% |
Loss on early extinguishment of debt | | — |
| | 12,883 |
| | (12,883 | ) | | nm |
|
Loss on derivative contracts | | 18,901 |
| | 20,233 |
| | (1,332 | ) | | (7 | )% |
Other income | | (1,311 | ) | | (637 | ) | | (674 | ) | | 106 | % |
Total | | $ | 19,749 |
| | $ | 44,350 |
| | | | |
| | | | | | | | |
Income tax (benefit) expense | | $ | 1,273 |
| | $ | (14 | ) | | $ | 1,287 |
| | (9,193 | )% |
Preferred stock dividends | | (7,295 | ) | | (7,295 | ) | | — |
| | — | % |
|
| | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
(in thousands) | | 2016 | | 2015 | | $ Change | | % Change |
Interest expense, net of capitalized amounts | | $ | 11,871 |
| | $ | 21,111 |
| | $ | (9,240 | ) | | (44 | )% |
Loss on early extinguishment of debt | | 12,883 |
| | — |
| | 12,883 |
| | nm |
|
(Gain) loss on derivative contracts | | 20,233 |
| | (28,358 | ) | | 48,591 |
| | (171 | )% |
Other income | | (637 | ) | | (198 | ) | | (439 | ) | | 222 | % |
Total | | $ | 44,350 |
| | $ | (7,445 | ) | | | | |
| | | | | | | | |
Income tax (benefit) expense | | $ | (14 | ) | | $ | 38,474 |
| | $ | (38,488 | ) | | (100 | )% |
Preferred stock dividends | | (7,295 | ) | | (7,895 | ) | | 600 |
| | (8 | )% |
nm = not meaningful
Interest expense, netExpense, Net of capitalized amounts. We finance a portionCapitalized Amounts. The following table sets forth the components of our capital expenditures, acquisitions and working capital requirements with borrowings under our Credit Facility or with term debt. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense, net of capitalized amounts. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense.
Interest expense, net of capitalized amounts incurred during the year ended December 31, 2017 decreased $9.7 million to $2.2 million compared to $11.9 million for the same period of 2016. The decrease is primarily attributable to a $13.9 million increase in capitalized interest compared to the 2016 period, resulting from a higher average unevaluated property balance for the year ended December 31, 2017 as compared to the same period of 2016. The increase in unevaluated property was primarily due to acquired properties(see Note 3 and 13 in the Footnotes to the Financial Statements for information about the Company’s acquisitions and unevaluated property balance).Offsetting the decrease was a $5.2 million increase in interest expense related to our debt due to a higher average debt balance for the year ended December 31, 2017 as compared to the same period of 2016, resulting from the issuance of an additional $200 million of our 6.125% Senior Notes in May 2017 (see Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s 6.125% Senior Notes).periods indicated:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2021 | | 2020 | | Change |
| | (In thousands) |
Interest expense on Senior Unsecured Notes | | $107,784 | | | $120,313 | | | ($12,529) | |
Interest expense on Second Lien Notes | | 43,791 | | | 9,188 | | | 34,603 | |
Interest expense on Credit Facility | | 31,647 | | | 45,912 | | | (14,265) | |
Amortization of debt issuance costs, premiums and discounts | | 18,309 | | | 7,325 | | | 10,984 | |
Other interest expense | | 128 | | | 190 | | | (62) | |
Capitalized interest | | (99,647) | | | (88,599) | | | (11,048) | |
Interest expense, net of capitalized amounts | | $102,012 | | | $94,329 | | | $7,683 | |
Interest expense, net of capitalized amounts, incurred during the year ended December 31, 2016 decreased $9.22021 increased $7.7 million to $11.9$102.0 million compared to $21.1$94.3 million for the same period of 2015.2020. The decreaseincrease is primarily attributabledue to the issuance of the Second Lien Notes at the end of the third quarter of 2020 as well as amortization of the discount associated with those Second Lien Notes. These increases were partially offset by the reduction in Senior Unsecured Notes outstanding as a $9.4 millionresult of the exchange of Senior Unsecured Notes for Second Lien Notes which occurred during the fourth quarter of 2020, lower borrowings on the Credit Facility, and an increase in capitalized interest comparedinterest.
(Gain)Losson Derivative Contracts. The net (gain) loss on derivative contracts for the periods indicated includes the following:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2021 | | 2020 | | Change |
| | (In thousands) |
(Gain) loss on oil derivatives | | $429,156 | | | ($48,031) | | | $477,187 | |
(Gain) loss on natural gas derivatives | | 33,621 | | | 14,883 | | | 18,738 | |
(Gain) loss on NGL derivatives | | 6,768 | | | 2,426 | | | 4,342 | |
(Gain) loss on contingent consideration arrangements | | (2,635) | | | 2,976 | | | (5,611) | |
(Gain) loss on September 2020 Warrants liability | | 55,390 | | | 55,519 | | | (129) | |
(Gain) loss on derivative contracts | | $522,300 | | | $27,773 | | | $494,527 | |
See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” of the Notes to our Consolidated Financial Statements for additional information.
(Gain) Losson Extinguishment of Debt. During November 2021, in connection with the 2015 period, resulting fromexchange of $197.0 million of our Second Lien Notes for 5.5 million shares of our common stock, we recorded a higher average unevaluated property balanceloss on extinguishment of debt of $43.4 million, which consisted of the notional amount of common stock issued less the aggregate principal amount of the Second Lien Notes exchanged, net of a pro-rata write-off of associated unamortized discount of $16.9 million and fees incurred. Additionally, during July 2021, we redeemed all of our 6.25% Senior Notes and recorded a gain on extinguishment of debt of $2.4 million, which was primarily related to writing off the remaining unamortized premium associated with the 6.25% Senior Notes.
During November 2020, in connection with the exchange of $389.0 million of our Senior Unsecured Notes for the Second Lien Notes, we recorded a gain on extinguishment of debt of $170.4 million, which consisted of the carrying values of the Senior Unsecured Notes exchanged less the aggregate principal amount of the Second Lien Notes issued, net of the associated debt discount of $9.1 million, which was based on the Second Lien Notes’ allocated fair value on the exchange date.
See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information.
Income Tax Expense. We recorded income tax expense of $0.2 million for the year ended December 31, 2016 as2021 compared to $122.1 million for the same period of 2015. The increase in unevaluated property was primarily due to acquired properties (see Note 3 in2020. Since the Footnotes to the Financial Statements for information about the Company’s acquisitions). Offsetting the decrease was a $0.2 million increase in interest expense related to our debt due to a higher average debt balance for the year ended December 31, 2016 as compared to the same periodsecond quarter of 2015, resulting from the issuance of our 6.125% Senior Notes in November 2016 (see Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s 6.125% Senior Notes).
Gain (loss)on the early extinguishment of debt. During October 2016, the secured second lien term loan was repaid in full at the prepayment rate of 101% using proceeds from the sale of the 6.125% Senior Notes, which resulted in a loss on early extinguishment of debt of $12.9 million (inclusive of $3.0 million in prepayment fees and $9.9 million of unamortized debt issuance costs). See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s debt.
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Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operation | |
Gain(loss)on derivative instruments. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in commodity prices. This amount represents the (i) gain (loss) related to fair value adjustments on our open derivative contracts and (ii) gains (losses) on settlements of derivative contracts for positions2020, we have concluded that have settled within the period.
For the year ended December 31, 2017, the net loss on derivative instruments was $18.9 million, compared to a $20.2 million net loss in 2016. The net gain (loss) on derivative instruments for the periods indicated includes the following (in thousands):
|
| | | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2017 | | 2016 | | Change |
Oil derivatives | | | | | | |
Net gain (loss) on settlements | | $ | (9,067 | ) | | $ | 17,801 |
| | $ | (26,900 | ) |
Net loss on fair value adjustments | | (11,426 | ) | | (37,543 | ) | | 26,100 |
|
Total loss on oil derivatives | | $ | (20,493 | ) | | $ | (19,742 | ) | | $ | (800 | ) |
Natural gas derivatives | | | | | | |
Net gain on settlements | | $ | 594 |
| | $ | 102 |
| | $ | 500 |
|
Net gain (loss) on fair value adjustments | | 998 |
| | (593 | ) | | 1,600 |
|
Total gain (loss) on natural gas derivatives | | $ | 1,592 |
| | $ | (491 | ) | | $ | 2,100 |
|
| | | | | | |
Total loss on oil & natural gas derivatives | | $ | (18,901 | ) | | $ | (20,233 | ) | | $ | 1,300 |
|
For the year ended December 31, 2016, the net loss on derivative instruments was $20.2 million, compared to a $28.4 million net gain in 2016. The net gain (loss) on derivative instruments for the periods indicated includes the following (in thousands):
|
| | | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2016 | | 2015 | | Change |
Oil derivatives | | | | | | |
Net gain on settlements | | $ | 17,801 |
| | $ | 33,299 |
| | $ | (15,500 | ) |
Net loss on fair value adjustments | | (37,543 | ) | | (5,403 | ) | | (32,100 | ) |
Total gain (loss) on oil derivatives | | $ | (19,742 | ) | | $ | 27,896 |
| | $ | (47,600 | ) |
Natural gas derivatives | | | | | | |
Net gain on settlements | | $ | 102 |
| | $ | 1,717 |
| | $ | (1,600 | ) |
Net loss on fair value adjustments | | (593 | ) | | (1,255 | ) | | 600 |
|
Total gain (loss) on natural gas derivatives | | $ | (491 | ) | | $ | 462 |
| | $ | (1,000 | ) |
| | | | | | |
Total gain (loss) on oil & natural gas derivatives | | $ | (20,233 | ) | | $ | 28,358 |
| | $ | (48,600 | ) |
See Notes 6 and 7 in the Footnotes to the Financial Statements for additional information on the Company’s derivative contracts and disclosures related to derivative instruments.
Income tax expense.We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. When appropriate based on our analysis, we record a valuation allowance for deferred tax assets when it is more likely than not that the net deferred tax assets will not be realized.realized and have recorded a full valuation allowance against our deferred tax assets, which still remained as of December 31, 2021. See “Note 12 – Income Taxes” of the Notes to our Consolidated Financial Statements for additional information regarding the valuation allowance.
Liquidity and Capital Resources
2022 Capital Budget and Funding Strategy. Our 2022 Capital Budget has been established at $725.0 million, with over 85% allocated towards development in the Permian with the balance towards development in the Eagle Ford. Because we are the operator of a high percentage of our properties, we can control the amount and timing of our capital expenditures. We plan to execute a moderated capital expenditure program through reduced reinvestment rates and balanced capital deployment for a more consistent cash flow generation and will be focused to further enhance our multi-zone, scaled development program to drive capital efficiency. See “Items 1 and 2. Business and Properties - Capital Budget” for additional details.
The Company hadfollowing table is a summary of our 2021 capital expenditures (1):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended | | Year Ended |
| March 31, 2021 | | June 30, 2021 | | September 30, 2021 | | December 31, 2021 | | December 31, 2021 |
| (In millions) |
Operational capital | $95.6 | | $138.3 | | $115.0 | | $159.7 | | $508.6 |
Capitalized interest | 24.0 | | 23.9 | | 26.1 | | 25.6 | | 99.6 |
Capitalized G&A | 11.2 | | 12.1 | | 10.4 | | 13.7 | | 47.4 |
Total | $130.8 | | $174.3 | | $151.5 | | $199.0 | | $655.6 |
(1) Capital expenditures, presented on an income tax expenseaccrual basis, includes drilling, completions, facilities, and equipment, and excludes land, seismic, and asset retirement costs.
We believe that existing cash and cash equivalents, any positive cash flows from operations and available borrowings under our revolving credit facility will be sufficient to support working capital, capital expenditures and other cash requirements for at least the next 12 months and, based on our current expectations, for the foreseeable future thereafter. Our future capital requirements, both near-term and long-term, will depend on many factors, including, but not limited to, commodity prices, market conditions, our available liquidity and financing, acquisitions and divestitures of $1.3oil and gas properties, the availability of drilling rigs and completion crews, the cost of completion services, success of drilling programs, land and industry partner issues, weather delays, the acquisition
of leases with drilling commitments, and other factors. We regularly consider which resources, including debt and equity financings, are available to meet our future financial obligations, planned capital expenditures and liquidity requirements.
In addition, depending upon our actual and anticipated sources and uses of liquidity, prevailing market conditions and other factors, we may, from time to time, seek to retire or repurchase our outstanding debt or equity securities through cash purchases in the open market or through privately negotiated transactions or otherwise. The amounts involved in any such transactions, individually or in aggregate, may be material. During 2021, to help manage our future financing cash outflows and liquidity position, we completed the exchange of $197.0 million of aggregate principal amount of our 9.00% Second Lien Senior Secured Notes for 5.5 million shares of our common stock, which reduced the long-term debt balance in our consolidated balance sheets and also reduced future interest payments.
We may consider divesting certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth or enter into joint venture agreements, provided we are able to divest such assets or enter into joint venture agreements on terms that are acceptable to us. During 2021, we sold certain non-core assets in the Delaware Basin, Eagle Ford Shale and Midland Basin for combined net proceeds of $181.8 million, which were used to repay borrowings outstanding under the Credit Facility.
Overview of Cash Flow Activities. For the year ended December 31, 20172021, cash and cash equivalents decreased $10.3 million to $9.9 million compared to an income tax benefit of less than $0.1$20.2 million at December 31, 2020.
| | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 |
| (In thousands) |
Net cash provided by operating activities | $974,143 | | | $559,775 | |
Net cash used in investing activities | (876,400) | | | (529,883) | |
Net cash used in financing activities | (108,097) | | | (22,997) | |
Net change in cash and cash equivalents | ($10,354) | | | $6,895 | |
Operating Activities. Net cash provided by operating activities was $974.1 million and $559.8 million for the same period of 2016.years ended December 31, 2021 and 2020, respectively. The changeincrease in income tax isoperating activities was primarily attributable to the following:
•An increase in revenue due to an increase in realized pricing; and
•Changes related to deferred state income tax expense.timing of working capital payments and receipts; offset by
•Increase in cash paid for commodity derivative settlements.
Investing Activities. Net cash used in investing activities was $876.4 million and $529.9 million for the years ended December 31, 2021 and 2020, respectively. The effective tax rate differed fromincrease in investing activities was primarily attributable to the federal income tax rate of 35% primarilyfollowing:
•A $480.8 million increase in acquisitions due to the valuation allowance for the comparative periods, the effect of state taxes, and non-deductible executive compensation expenses.Primexx acquisition; offset by
•A decrease in capital expenditures.
The Company had an income tax benefit of less than $0.1 million forFinancing Activities. For the year ended December 31, 20162021, net cash used in financing activities was $108.1 million compared to an income tax expense$23.0 million during 2020. The increase in net cash used in financing activities was primarily attributable to the following:
•Redemption of $38.5the 6.25% Senior Notes in July 2021; and
•Repayments on the Credit Facility; offset by
•The issuance of $650.0 million forof 8.00% Senior Notes in July 2021
Credit Facility. As of December 31, 2021, our Credit Facility had a maximum credit amount of $5.0 billion, a borrowing base and elected commitment amount of $1.6 billion, with borrowings outstanding of $785.0 million at a weighted-average interest rate of 2.65%, and letters of credit outstanding of $24.0 million. The borrowing base under the same periodcredit agreement is subject to regular redeterminations in the spring and fall of 2015. The changeeach year, as well as special redeterminations described in income tax is primarily related to recording a valuation allowance of $108.8the credit agreement, which in 2015 and the difference ineach case may reduce the amount of income (loss) before income taxes between periods.the borrowing base. On November 1, 2021, we entered into the fifth amendment to our credit agreement governing the Credit Facility which, among other things, reaffirmed the borrowing base and elected commitment amount of $1.6 billion as a result of the fall 2021 scheduled redetermination.
Our Credit Facility contains certain covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. Under the Credit Facility, we currently must maintain the following financial covenants determined as of the last day of the quarter: (1) commencing on March 31, 2020 and for each quarter ending on or prior to December 31, 2021, a Secured Leverage Ratio of no more than 3.00 to 1.00; (2) commencing March 31, 2022 and for each quarter ending thereafter, a Leverage Ratio of no more than 4.00 to 1.00; and (3) a Current Ratio of not less than 1.00 to 1.00. We were in compliance with these covenants at December 31, 2021.
Second Lien Note Exchange.On November 5, 2021, we closed on the agreement with Chambers Investments, LLC (“Kimmeridge”), a private investment vehicle managed by Kimmeridge Energy Management, LLC, to exchange $197.0 million of our outstanding Second Lien Notes, for a notional amount of approximately $223.1 million of our common stock, which equated to 5.5 million shares.
8.00% Senior Notes and Redemption of 6.25% Senior Notes.On July 6, 2021, we issued $650.0 million aggregate principal amount of 8.00% Senior Notes due 2028 in a private placement for proceeds of approximately $638.1 million, net of underwriting discounts and commissions and offering costs. The effective tax rate8.00% Senior Notes mature on August 1, 2028 and interest is payable semi-annually each February 1 and August 1, commencing on February 1, 2022. On June 21, 2021, we delivered a redemption notice with respect to all $542.7 million of 0% in 2016 and (19)% in 2015 differedour outstanding 6.25% Senior Notes due 2023, which became redeemable on July 21, 2021. We used a portion of the net proceeds from the federal income tax rate8.00% Senior Notes to redeem all of 35% primarily dueour outstanding 6.25% Senior Notes and the remaining proceeds to partially repay amounts outstanding under the valuation allowanceCredit Facility.
See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information on our long-term debt.
Material Cash Requirements
As of December 31, 2021, we have financial obligations associated with our outstanding long-term debt, including interest payments and principal repayments. See “Note 7 – Borrowings” of the comparative periods,Notes to our Consolidated Financial Statements for further discussion of the effectcontractual commitments under our debt agreements, including the timing of state taxes,principal repayments. Additionally, we have operational obligations associated with long-term, non-cancelable leases, drilling rig contracts, frac service contracts, gathering, processing and non-deductible executive compensation expenses.transportation service agreements, and estimates of future asset retirement obligations. See “Note 14 – Asset Retirement Obligations” and “Note 17 – Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for additional details.
We estimate that the combination of our sources of capital, as discussed above, will continue to be adequate to fund our short- and long-term contractual obligations.
Other Commitments
The following table includes our current oil sales contracts and firm transportation agreements as of December 31, 2021: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Type of Commitment (1) | | Region | | Execution Date | | Start Date | | End Date | | Committed Volumes (Bbls/d) |
Oil sales contract | | Permian | | October 2021 | | January 2022 | | December 2022 | | 7,500 |
Oil sales contract | | Permian | | July 2019 | | August 2021 | | July 2026 | | 5,000 |
Oil sales contract | | Permian | | June 2019 | | January 2020 | | December 2024 | | 10,000 |
Oil sales contract | | Permian | | August 2018 | | April 2020 | | March 2022 | | 15,000 |
Firm transportation agreement (2)(3) | | Permian | | June 2019 | | August 2020 | | July 2030 | | 10,000 |
Firm transportation agreement (2) | | Permian | | August 2018 | | April 2020 | | March 2027 | | 15,000 |
| | |
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operation | |
The following table presents a reconciliation(1)For each of the federal statutory tax ratescommitments shown in the table above, the committed barrels may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. We expect to fulfill these delivery commitments with our existing production or through the effective tax rates:purchases of third-party commodities.
(2)Each of the firm transportation agreements shown in the table above grant us access to delivery points in several locations along the Gulf Coast.
(3)The committed volumes shown in the table above for this particular firm transportation agreement are average volumes. For the terms of August 2020-July 2023, August 2023-July 2027 and August 2027-July 2030, the committed volumes are 7,500 Bbls/d, 10,000 Bbls/d and 12,500 Bbls/d, respectively.
The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess
We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer credit risk. We mitigate these risks through a program of risk management including the use of commodity derivative instruments.
Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these entities will participate in our wells. At December 31, 2017 ourWe generally have the right to withhold future revenue distributions to recover past due receivables from joint interest receivables were approximately $42.7 million.owners.