Item 1A. Risk Factors
Risk Factors
Depressed oil and natural gas prices may adversely affect our results of operations and financial condition. Our success is highly dependent on prices for oil and natural gas, which are extremely volatile, and the oil and natural gas markets are cyclical. Extended periods of low prices for oil or natural gas will have a material adverse effect on us. The prices of oil and natural gas depend on factors we cannot control such as weather, economic conditions, and levels of production, actions by OPEC and other countries and government actions. Prices of oil and natural gas will affect the following aspects of our business:
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our revenues, cash flows and earnings;
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the amount of oil and natural gas that we are economically able to produce;
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our ability to attract capital to finance our operations and the cost of the capital;
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the amount we are allowed to borrow under our credit facilities;
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the profit or loss we incur in exploring for and developing our reserves; and
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the value of our oil and natural gas properties.
Any substantial and extended decline in the price of oil or natural gas could have an adverse effect on our borrowing capacity, our ability to obtain additional capital, and our revenues, profitability and cash flows.
If oil and natural gas prices decrease and remain depressed for extended periods of time, we may be required to take additional writedowns of the carrying value of our oil and natural gas properties. We may be required to writedown the carrying value of our oil and natural gas properties when oil and natural gas prices are low. 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%, of future net cash flows from estimated net proved reserves, using the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month, plus the lower of cost or fair market value of our unproved properties. If net capitalized costs of our oil and natural gas properties exceed this 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 writedown of oil and natural gas properties is not reversible at a later date, even if prices increase. See Note 12 to our Consolidated Financial Statements.
Our actual recovery of reserves may substantially differ from our proved reserve estimates and our proved reserve estimates may change over time. This 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 process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. In addition, drilling, testing and production data acquired since the date of an estimate may justify revising an estimate.
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. Additionally, 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. We incorporate many factors and assumptions into our estimates including:
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Expected reservoir characteristics based on geological, geophysical and engineering assessments;
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Future production rates;
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Future oil and natural gas prices and quality and locational differences; and
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Future development and operating costs.
You should not assume that any present value of future net cash flows from our estimated net proved reserves contained in this Form 10-K represents the market value of our oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves at December 31, 2013 on average 12-month 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, 2013, approximately 33% of the discounted present value of our estimated net proved reserves consisted of PUDs. PUDs represented 50% 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 undeveloped reserves 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 use to calculate the net present value of future net revenues and cash flows 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.
Information about reserves constitutes forward-looking information. See “Forward-Looking Statements” for information regarding forward-looking information.
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. 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. We may not be successful in exploring for, developing or acquiring additional reserves.
Exploring for, developing, or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop, or acquire additional reserves, or may not be able to make the necessary capital investments to develop our reserves, if our cash flows from operations decline or external sources of capital become limited or unavailable. As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques. The utilization of these techniques requires substantially greater capital expenditures, currently expected to be in excess of three times the cost, as compared to the drilling of a traditional vertical well. If we do not replace the reserves we produce, our reserves revenues and cash flow will decrease over time, which will have an adverse effect on our business.
Our business requires significant capital expenditures and we may not be able to obtain needed capital or financing on satisfactory terms or at all. Our exploration and development activities are capital intensive. 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 funded our capital expenditures through a combination of cash flows from operations, borrowings under our credit facility and public debt and equity financings. In 2013, our total capital expenditures, including expenditures for leasehold interests and property acquisitions, drilling, seismic and infrastructure, were approximately $171 million. Our 2014 capital budget for drilling, completion and infrastructure is estimated to be approximately $185 million. 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, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.
If the borrowing base under our revolving credit facility or our revenues 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 able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or cash available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing 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, and could adversely affect our business, financial condition and results of operations.
Our revolving credit facility and second lien term loan facility contain restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities. Our credit facilities restrictive covenants that limit our ability to, among other things:
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incur additional indebtedness;
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create additional liens;
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sell assets;
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merge or consolidate with another entity;
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pay dividends or make other distributions;
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engage in transactions with affiliates; and
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enter into certain swap agreements.
In addition, we will be required to use substantial portions of our future cash flow to repay principal and interest on our indebtedness. Our credit facilities require us to maintain certain financial ratios and tests, including a minimum asset value coverage ratio of total debt. The requirement that we comply with these provisions may materially adversely affect our ability to react to changes
in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.
Our borrowings under our revolving credit facility and second lien term loan facility expose us to interest rate risk. Our earnings are exposed to interest rate risk associated with borrowings under our revolving credit facility, which bear interest at a rate elected by us that is based on the prime, LIBOR or federal funds rate plus margins ranging from 0.75% to 2.75% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. Our second lien term loan facility bears interest at a rate of LIBOR plus 7.75%. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.
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 has 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 rise as the number of active rigs in service 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 or qualified personnel can materially and adversely affect our operations and profitability.
Our operations substantially depend on the availability of water. Restrictions on our ability to obtain, dispose of or recycle 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 our drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local landowners and other sources for use in our operations. During the last few years, West Texas has experienced extreme drought conditions. As a result of the severe drought, some local water districts may begin restricting the use of water under their jurisdiction for drilling and hydraulic fracturing to protect the local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil, NGLs and natural gas, which could have an adverse effect on our business, financial condition and results of operations.
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.
Our exploration projects increase the risks inherent in our oil and natural gas activities. We may seek to replace reserves through exploration, where the risks are greater than in acquisitions and development drilling. During 2012, we purchased 21,419 net acres in the Northern Midland basin, an area that has seen only limited drilling activity. We expect to continue exploration of this acreage over the next several years, although our position is subject to meaningful lease expirations through 2015. Our exploration drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
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the results of our exploration drilling activities;
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receipt of additional seismic data or other geophysical data or the reprocessing of existing data;
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material changes in oil or natural gas prices;
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the costs and availability of drilling rigs;
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the success or failure of wells drilled in similar formations or which would use the same production facilities;
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availability and cost of capital;
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changes in the estimates of the costs to drill or complete wells; and
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changes to governmental regulations.
Delays in exploration, cost overruns or unsuccessful drilling results could have a material adverse effect on our business and future growth.
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, including the risk that commercially productive deposits will not be discovered. 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, not only from dry wells but also from 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:
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unexpected drilling conditions;
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pressure or irregularities in formations;
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equipment failures or accidents and shortages or delays in the availability of drilling rigs and the delivery of equipment; and
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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 oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system, marketing and transportation constraints, regulatory approvals and other 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.
We may be unable to integrate successfully the operations of future acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisitions. Our business may include producing property acquisitions that would include undeveloped acreage. We can offer no assurance that we will achieve the desired profitability 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:
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operating a larger combined organization and adding operations;
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difficulties in the assimilation of the assets and operations of the acquired business, especially if the assets acquired are in a new geographic area;
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risk that oil and natural gas reserves acquired may not be of the anticipated magnitude or may not be developed as anticipated;
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loss of significant key employees from the acquired business:
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diversion of management’s attention from other business concerns;
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failure to realize expected profitability or growth;
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failure to realize expected synergies and cost savings;
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coordinating geographically disparate organizations, systems and facilities; and
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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, 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 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.
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 producing oil and natural gas, including:
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our drilling operations may encounter unexpected formations or pressures, which could cause damage to equipment or personal injury;
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we may experience equipment failures which curtail or stop production;
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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;
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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 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, 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:
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injury or loss of life;
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severe damage to and destruction of property, natural resources and equipment;
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pollution and other environmental damage;
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clean-up responsibilities;
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regulatory investigation and penalties;
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suspension of our operations; and
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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.
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:
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the extent of domestic production and imports of oil and natural gas;
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the proximity of the natural gas production to natural gas and NGL pipelines;
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the availability of pipeline capacity;
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the demand for oil and natural gas by utilities and other end users;
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the availability of alternative fuel sources;
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the effects of inclement weather;
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state and federal regulation of oil and natural gas marketing; and
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federal regulation of natural gas sold or transported in interstate commerce.
In particular, in areas with increasing non-conventional shale drilling activity, capacity may be limited and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built.
Part of our strategy involves drilling in new or emerging shale formations using horizontal drilling and completion techniques. The results of our planned drilling program in these formations may be subject to more uncertainties than conventional drilling programs in more established formations and may not meet our expectations for reserves or production. The results of our recent horizontal drilling efforts in new or emerging formations, including the Wolfcamp shale, Cline shale, and Mississippian lime in the Permian basin, are generally more uncertain than drilling results in areas that are developed and have established production. Because new or emerging formations have limited or no production history, we are less able to rely on past drilling results in those areas as a basis predict our future drilling results. 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 areas may not be as economic as we anticipate, we could incur material writedowns of unevaluated properties and the value of our undeveloped acreage could decline in the future.
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 from proved properties 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.
We may not be insured against all of the operating risks to which our business is exposed. In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We cannot assure you that our insurance will be adequate to cover losses or liabilities. 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 insurance in the future at rates we consider reasonable and may elect none or minimal insurance coverage. The occurrence of a significant event, not fully insured or indemnified against, could have a material adverse effect on our financial condition and operations.
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. 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 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:
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our access to the capital necessary to drill wells and acquire properties;
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our ability to acquire and analyze seismic, geological and other information relating to a property;
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our ability to retain the personnel necessary to properly evaluate seismic and other information relating to a property;
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our ability to procure materials, equipment and services required to explore, develop and operate our properties, including the ability to procure fracture stimulation services on wells drilled; and
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our ability to access pipelines, and the location of facilities used to produce and transport oil and natural gas production.
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 “Act”) establishes federal oversight and regulation of over-the-counter derivatives and requires the Commodity Futures Trading Commission (the “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.
In its rulemaking under the new legislation, the CFTC has issued a final rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions); the CFTC’s final rule was set aside by the U.S. District Court for the District of Columbia on September 28, 2012 and remanded to the CFTC to resolve ambiguity as to whether statutory requirements for such limits to be determined
necessary and appropriate were satisfied. The CFTC appealed this ruling but subsequently withdrew its appeal. On November 5, 2013, the CFTC approved a Notice of Proposed Rulemaking designed to implement new position limits regulation. The impact of such regulations upon our business is not yet clear. Certain of our hedging and trading activities and those of our counterparties may be subject to the position limits, which may reduce our ability to enter into hedging transactions.
The Act provides a limited exception to end users (such as us) from the requirement to use cleared exchanges, rather than hedging over-the-counter and authorizes the CFTC to set requirements to post margin in connection with hedging activities. While it is not possible at this time to predict when the CFTC will finalize certain other related rules and regulations, the Act and related regulations may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although whether these requirements will apply to our business is uncertain at this time. If the regulations ultimately adopted require that we post margin for our hedging activities or require our counterparties to hold margin or maintain capital levels, the cost of which could be passed through to us, or impose other requirements that are more burdensome than current regulations, hedging transactions in the future would become more expensive than we experienced in the past.
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 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. Additionally, we are required to pay the difference between the floating price and the fixed price when the floating price exceeds the fixed price 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 production.
By hedging, we may not benefit from price increases. Hedging can prevent us from receiving the full advantage of increases in oil or natural gas prices above the fixed amount specified in a hedge transaction in the case of a swap. We also enter into price “collars” to reduce the risk of changes in oil and natural gas prices. Under a collar, no payments are due by either party so long as the market price is above a floor set in the collar and below a ceiling. If the price falls below the floor, the counter-party to the collar pays the difference to us and if the price is above the ceiling, we pay the counter-party the difference. Another type of hedging contract we have entered into is a put contract. Under a put, if the price falls below the set floor price, the counter-party to the contract pays the difference to us. See “Quantitative and Qualitative Disclosures About Market Risks” for a discussion of our hedging practices.
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. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract.
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 38% of our total oil and natural gas revenues for the year ended December 31, 2013. 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. Joint interest receivables arise from billing entities who own a partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells.
Compliance with environmental and other government regulations could be costly and could negatively impact production. Our operations are subject to numerous laws and regulations governing the operation and maintenance of our facilities and the discharge of materials into the environment or otherwise relating to environmental protection. For a discussion of the material regulations applicable to us, see “Regulations.” These laws and regulations may:
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require that we acquire permits before commencing drilling;
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impose operational, emissions control and other conditions on our activities;
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restrict the substances that can be released into the environment in connection with drilling and production activities;
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limit or prohibit drilling activities on protected areas such as wetlands and wilderness areas; and
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require measures to remediate or mitigate pollution and environmental impacts from current and former operations, such as cleaning up spills or dismantling abandoned production facilities.
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 and increased public services, as well as administrative, civil and criminal fines and penalties, and injunctive relief. We could also be affected by more stringent laws and regulations adopted in the future, including any related climate change, greenhouse gases 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 or we may be required to cease production from properties in the event of environmental incidents.
Climate change legislation or regulations restricting emissions of “greenhouse gasses” could result in increased operating costs and reduced demand for the oil and natural gas we produce. The EPA has adopted its so-called “GHG tailoring rule” that phases in federal PSD permit requirements for GHG emissions from new sources and modification of existing sources, federal Title V operating permit requirements for all sources, based upon their potential to emit specific quantities of GHGs. These permitting provisions to the extent applicable to our operations could require us to implement emission controls or other measures to reduce GHG emissions and we could incur additional costs to satisfy those requirements.
In addition, , the EPA requires the reporting of GHG emissions from specified large GHG emission sources in the United States beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA published its amendments to the GHG reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities, which may include facilities we operate. Reporting of GHG emissions from such facilities is required on an annual basis, beginning in 2012 for emissions occurring in 2011, if the total emissions within a basin exceed 25,000 metric tons CO2 equivalent per year. We will incur costs associated with this monitoring obligation and potentially additional reporting costs if production growth triggers the emission threshold.
In addition, the United States Congress has considered legislation to reduce emissions of GHGs and many states have already taken or have considered legal measures to reduce or measure GHG emissions, often involving the planned development of GHG emission inventories and/or cap and trade programs. Most of these cap and trade programs would require major sources of emissions or major producers of fuels to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. These allowances would be expected to escalate significantly in cost over time. The adoption and implementation of any legislation or regulatory programs imposing GHG reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGS associated with our operations or could adversely affect demand for the oil and natural gas that we produce.
Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects. In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including storms and floods), the arability of farmland, and water availability and quality. If such effects were to occur, our exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production activities either because of climate-related damages to our facilities in our costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect affect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic fracturing operations require large amounts of water. Should drought conditions occur, our ability to obtain water in sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly.
Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing 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. The process is typically regulated by state oil and gas commissions but is not subject to regulation at the federal level (except for fracturing activity involving the use of diesel). We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with the wells for which we are the operator. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result
in fines, penalties, and remediation costs, among other sanctions and liabilities under federal and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury. In March 2010, the EPA announced that it would conduct a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. A progress report was issued in December 2012, with final results expected in 2014. The agency also announced that one of its enforcement initiatives for 2011 to 2013 would be to focus on environmental compliance by the energy extraction sector. This study and enforcement initiative, could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.
A committee of the U.S. House of Representatives conducted an investigation of hydraulic fracturing practices. Legislation was introduced before Congress, but not passed to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states and local or regional regulatory authorities have adopted or are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example, New York has imposed a de facto moratorium on the issuance of permits for high-volume, horizontal hydraulic fracturing until state-administered environmental studies are finalized. Further, Pennsylvania has adopted a variety of regulations limiting how and where fracturing can be performed. While we have no operations in either New York or Pennsylvania, any other new laws or regulations that significantly restrict hydraulic fracturing in areas in which we do operate could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect the determination of whether a well is commercially viable. Further, EPA has announced initiatives under the CWA to establish standards of wastewater from hydraulic fracturing and under TSCA to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals, and the BLM has indicated that it will continue with rulemaking to regulate hydraulic fracturing on federal lands. In addition, if hydraulic fracturing is regulated at the federal level, our fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. In addition, restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we are ultimately able to produce in commercial quantities.
Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation. In recent years, the Obama administration’s budget proposals and other proposed legislation have included the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production. If enacted into law, these proposals would eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. These changes include, but are not limited to (1) the repeal of the percentage depletion allowance for oil and gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for U.S. production activities and (4) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for or development of, oil and gas within the United States. It is unclear whether any such changes will be enacted or how soon any such changes would become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could negatively affect the Company’s financial condition and results of operations.
There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm our business may occur and not be detected. Our management, including our Chief Executive Officer and Chief Financial Officer, do not expect that our internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance that all material control issues and instances of fraud, if any, in our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. A failure of our controls and procedures to detect error or fraud could seriously harm our business and results of operations.
We have no plans to pay cash dividends on our common stock in the foreseeable future. We have no plans to pay cash dividends in the foreseeable future. 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. In addition, the terms of our credit facilities prohibit us from paying dividends and making other distributions.
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 and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production operations. 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-attack 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.
While we have not experienced cyber-attacks, there is no assurance that we will not suffer such attacks and resulting losses in the future. Further, as cyber-attacks 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.
ITEM 1B.
ITEM 1B. Unresolved Staff Comments
None.
ITEM 3.
ITEM 3. Legal Proceedings
We are a defendant in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material effect on our financial position or results of operations.
ITEM 4.
ITEM 4. Mine Safety Disclosures
Not applicable.
PART II.
ITEM 5.
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 under the symbol “CPE”. The following table sets forth the high and low sale prices per share as reported for the periods indicated.
Holders
As of March 10, 2014 the Company had approximately 3,111 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 intend to reinvest our cash flows and earnings into our business. The declaration and payment of dividends 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.
Holders of our Series A preferred stock are entitled to a cumulative dividend whether or not declared, of $5.00 per annum, payable quarterly, equivalent to 10% of the liquidation preference of $50.00 per share. Unless the full amount of the dividends for the Series A Preferred Stock is paid in full, we cannot declare or pay any dividend on our common stock. In addition, certain of our debt facilities contain restrictions on the payment of dividends to the holders of our common stock.
During the fourth quarter of 2013, neither the Company nor any affiliated purchasers made repurchases of Callon’s equity securities.
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, 2013 (securities amounts are presented in thousands).
For additional information regarding the Company’s benefit plans and share-based compensation expense, see Notes 7 and 8 to the Consolidated 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 four broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance.
Consistent with the Company’s prior year performance graph, the 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 New York Stock Exchange Market Index and New York Stock Exchange Market Index from December 31, 2008, through December 31, 2013. The Company plans to replace these indexes with S&P 500 Index and the SIG Oil Exploration & Production Index, which is believes provides a more meaningful comparison and is reflective of the indexes more commonly used by the Company’s peer group. Consequently, these indexes have also been added to the graph below, and we expect will be used in future year’s performance graphs.
The stock 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 Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.
Comparison of Five Year Cumulative Total Return
Assumes Initial Investment of $100
December 2013
ITEM 6.
ITEM 6. Selected Financial Data
The following table sets forth, as of the dates and for the periods indicated, selected financial information about us. The financial information for each of the five years in the period ended December 31, 2013 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.
(a)
Following the decisions resulting from several court cases brought by another oil and gas company, the court ruled that the BOEM was not entitled to receive these royalty payments. The amount above reflects royalty recoupments for production from the fields 2003 inception through December 31, 2008, which were accrued at December 31, 2009 and paid by the BOEM during 2010.
(b)
Net income for 2011 includes $69.3 million of income tax benefit related to the reversal of the Company’s deferred tax asset valuation allowance. See Note 10 for additional information.
(c)
2013 and 2012 long-term debt includes a non-cash deferred credit of $5,267 and $13,707, respectively that will be amortized into earnings as a reduction to interest expense over the life of the 13% Senior Notes due 2016. See Note 4 for additional information.
(d)
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.
ITEM 7.
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
The following management’s discussion and analysis is intended to assist in understanding the principal factors affecting the Company’s 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.
We have been engaged in the exploration, development, acquisition and production of oil and natural gas properties since 1950.
Significant accomplishments for 2013 include:
•
Increased 2013 Permian Basin annual production by 38% to 813 MBOE as compared to 2012;
•
Exceeded our “exit rate” target production rate for 2013, producing 3,611 BOE/d from our Permian operations in the month of December;
•
Increased 2013 Permian Basin proved reserves by 58% to 14.9 MMBOE as compared to 2012;
•
Replaced 708% of Permian production with net Permian proved reserve additions, net of revisions;
•
Drilled a total of 17 horizontal wells in the Southern Midland Basin, producing from two established zones in the Wolfcamp B and the Wolfcamp A;
•
Acquired our Garrison Draw field inclusive of 2,186 net acres and associated production in Reagan County for $11 million, which further added to our inventory of horizontal well locations. Subsequently, we expanded this acreage position to accommodate the drilling of long laterals;
•
Accelerated offshore cash flows for onshore redeployment with the sale of our interest in the Medusa and our remaining shelf fields for $100 million before customary purchase price adjustments, and
•
Raised $70.0 million from the issuance of Series A Cumulative Preferred Stock,
•
Retired 50% of our Senior Notes, improving our cost of capital, and
•
Received the Midland Bruno Hanson/Midland College Award for Environmental Excellence recognizing our commitment to strong environmental stewardship in the Permian Basin.
Permian Production Growth and Well Counts
Following the sale of our remaining offshore and Haynesville properties in the fourth quarter of 2013, all of our producing properties are located in the Permian Basin. Our production in the Permian grew 38% in 2013 compared to 2012, increasing to 813 MBOE from 591 MBOE, respectively. Production in 2013 continued to benefit from high oil concentrations including 64% oil and 36% natural gas, which we anticipate to further increase following the sale of our offshore assets.
Callon Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations
On average, we operated 1.4 horizontal rigs and one vertical rig in 2013, and drilled a total of 26 gross (22.2 net) wells, of which 1 gross (0.4 net) well was recompleted during the year and 5 gross (4.7 net) were awaiting completion at December 31, 2013.
(a) Completions include wells drilled prior to 2013.
Permian Reserve Growth
As of December 31, 2013, our estimated Permian proved reserves increased 58% to 14.9 MMBOE compared to 9.4 MMBOE of Permian proved reserves at year-end 2012. In total, proved reserves increased 6%, or 0.8 MMBOE, to 14.9 MMBOE from 14.1 MMBOE for as of the same date in 2012 as our significant growth in Permian proved reserves was largely offset by the sale of our offshore and Haynesville properties and by the reclassification of previously recorded Permian vertical development proved undeveloped reserves as we focus on horizontal development. Our Permian Basin proved reserves at year-end 2013 were 80% oil and 20% natural gas, compared to 76% oil and 24% natural gas at year-end 2012.
Callon Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations
2013 Preferred Equity Offering
On May 30, 2013, the Company issued $75.0 million of 10.0% Series A Cumulative Preferred Stock (the “Preferred Stock”) and received $70.0 million net proceeds after deducting the underwriting commissions and offering expenses. We used the proceeds of this equity offering to repay outstanding borrowings under our revolving Credit Facility, to fund accelerated capital expenditures to further develop and evaluate our Permian asset base, and for general corporate purposes.
Liquidity and Capital Resources
Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions and the sale of debt and equity securities. Our primary uses of capital have been for the acquisition, development and exploration of oil and natural gas properties. Cash and cash equivalents increased $1.9 million during 2013 to $3.0 million compared to $1.1 million at December 31, 2012. We recently entered into the Amended Credit Facility and Second Lien Facility to support the funding of our ongoing operations. For additional information, see Note 4 to the Consolidated Financial Statements. We believe that, as discussed below, our operating cash flows combined with our bank borrowing ability provides the liquidity necessary to meet our operational cash flow needs.
Liquidity and cash flow:
Operating Activities. For the year ended December 31, 2013, net cash provided by operating activities was $54.3 million, compared to $51.3 million for the same period in 2012. The increase was related primarily to a 15% decrease in lease operating expenses coupled with a 3% increase in the average sales price on an equivalent basis partially offset by lower revenues as oil and natural gas production decreased 7% and 16%, respectively. Production and realized prices are discussed below in Results of Operations.
Investing Activities. For the year ended December 31, 2013, net cash used in investing activities was $79.8 million as compared to $93.7 million for the same period in 2012. The net $13.9 million decrease in cash used in investing activities is primarily attributable to a $50.1 million increase in proceeds from the sale of mineral interests and equipment offset by a 26.4 million increase in capital expenditures related to development activity on our Permian basin acreage and $10.9 million for producing property acquisitions. The $50.1 million increase in the previously mentioned proceeds relates to the proceeds in 2013 of $90.0 million, primarily attributable to the sale of our Medusa and offshore properties compared to proceeds in 2012 of $39.9 million, primarily related to the sale of our Habanero offshore property, which are both discussed below and in Note 12 to the financial statements. The $26.4 million increase in capital expenditures included the costs associated with expanding to a two-rig drilling program and the acquisition of the Garrison Draw property.
2014 Budgeted Capital Expenditures
In early February 2014, we announced our operational capital budget for 2014:
Callon Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations
We expanded our horizontal pad development efforts from two to four fields in late 2013, adding Carpe Diem in Midland County and Garrison Draw in Reagan County. We expect our 2014 horizontal drilling program will be primarily focused on program development of established Upper and Lower Wolfcamp zones in the Southern and Central Midland Basin, but will also include two wells in the Southern Midland Basin to evaluate the Wolfcamp A shale and a test of the Lower Spraberry shale formation in the Central Midland Basin. In addition, we anticipate the average lateral length of our horizontal wells in 2014 to be approximately 7,000’ per well.
Planned vertical drilling activity is anticipated to be limited to five deep Wolfberry wells in the Pecan Acres field, one well in the Garrison Draw field. We have included three vertical exploration wells in the Northern Midland Basin, the timing and location of which being subject to change as results are evaluated during the course of 2014.
In addition to the operational capital expenditures above, we budgeted approximately $25 million for capitalized expenses and certain retained plugging abandonment expenses related to divested Gulf of Mexico shelf assets.
Our 2014 capital program is 100% operated and, as a result, the amount and timing of these capital expenditures are largely discretionary depending on commodity prices and other factors. We expect to fund our 2014 capital program through a combination of cash flow from operations, bank borrowings and term debt issuance, including our recently executed Second Lien Facility.
Financing Activities. For the year ended December 31, 2013, net cash provided by financing activities was $27.3 million compared to cash used by financing activities of $0.3 million during the same period of 2012. Net cash provided by financing activities for 2013 included proceeds of $70.4 million, net from our Preferred Stock offering (see Note 9 for additional information) and a $12 million draw, net on our Credit Facility offset by the $50 million redemption of our Senior Notes, and approximately $4.6 million in preferred stock dividends.
Senior Secured Credit Facility (“Credit Facility”)
The Company’s $200 million Credit Facility, for which Regions Bank serves as the Administrative Agent, matures March 15, 2016 and includes Citibank, NA, IberiaBank, Whitney Bank and OneWest Bank, FSB as participating lenders. As of December 31, 2013, the Company’s Credit Facility had an approved borrowing base at December 31, 2013 of $83 million. The Credit Facility was secured by mortgages covering the Company’s major producing fields. As of December 31, 2013, the balance outstanding on the Credit Facility was $22 million with an interest rate of 2.92%, calculated as the London Interbank Offered Rate (LIBOR), plus a tiered rate ranging from 2.5% to 3.0%, which is determined by utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum on the unused portion of the borrowing base, which is payable quarterly.
Subsequent to December 31, 2013, the Company amended its existing Credit Facility as discussed below. Additionally, the Company executed the Second Lien Facility also discussed below.
Amended Credit Facility (the “Amended Credit Facility”) and Second Lien Term Loan Facility (the “Second Lien Facility”)
On March 11, 2014, we entered into an amended senior secured revolving credit facility (the “Amended Credit Facility”) in the amount of $500 million with JPMorgan Chase Bank, N.A. as Administrative Agent (“J.P. Morgan”). The Credit Facility will have an initial borrowing base amount of $95 million and a maturity date of March 11, 2019. In conjunction with the Amended Credit Facility, we entered into a senior secured second lien term loan facility (the “Second Lien Facility”) in an aggregate amount of up to $125 million with J.P. Morgan as Administrative Agent and with a maturity date of September 11, 2019. See Note 4 for additional information.
13% Senior Notes due 2016 (the “Senior Notes”) and Deferred Credit
As of December 31, 2013, following a $48.5 million principal redemption in December 2013, we had approximately $48.5 million principal amount of the 13% Senior Notes due 2016 outstanding with interest payable quarterly.
Callon Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Contractual Obligations
The following table includes the Company’s current contractual obligations and purchase commitments, at which time the Company had no product delivery commitments:
(a)
The <1 Year column includes $2,055 related to the early termination provisions of one of the Company’s horizontal drilling rigs (See Note 13), which the Company replaced with a different horizontal rig, and the amount assumes the lessor is unable to re-charter the rig and staffing personnel to another lessee. Should the lessor re-charter the rig and its related personnel to a new lessee, the $2,055 would be reduced by the value of the new lessee’s rentals. Also includes an anticipated contract renewal of our Cactus 1 Rig lease.
Income Taxes
The Company’s income tax expense varies from the statutory rate primarily due to the effect of state taxes, non deductible compensation under Section 162(m) and restricted stock offset by percentage depletion. Prior to 2012, we carried a full valuation allowance against our net deferred tax asset. The income tax benefit of $69.3 million in 2011 resulted primarily from the reversal of the valuation allowance established in 2008 against our net deferred tax assets. For additional information, see the Income Tax discussion included below in Results of Operations and Note 10 to the Consolidated Financial Statements.
Callon Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Results of Operations
The following table sets forth certain unaudited operating information with respect to the Company’s oil and natural gas operations for the periods indicated:
(a)
Oil prices for production from our two divested deepwater fields reflect a premium over NYMEX pricing based on Mars WTI differential for Medusa production, prior to the sale of Medusa in December 2013, and Argus Bonita WTI differential for Habanero production, prior to the sale of Habanero during December 2012.
(b)
As discussed in Note 5, the Company discontinued hedge accounting beginning with derivative contracts executed on January 1, 2012. Consequently, the gain or loss on derivative contracts, settled is now included in the statement of operations within Loss (Gain) on derivative contracts. The amounts reported above reflect the realized portion of derivative contracts designated as cash flow hedges.
(c)
Natural gas prices exceeded the related NYMEX prices, which are quoted on an MMBtu basis, primarily due to the value of the NGLs in our liquids-rich natural gas stream, primarily from our Permian basin production.
Callon Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Revenues
The following tables are intended to reconcile the change in oil, natural gas and total revenue for the respective periods presented by reflecting the effect of changes in volume, changes in the underlying commodity prices and the impact of our hedge program. (in thousands)
Oil Revenue
For the year ended December 31, 2013, oil revenues of $89.0 million decreased $7.6 million, or 8%, compared to revenues of $96.6 million for the year ended December 31, 2012. Lower production from our offshore properties, primarily related to the sale of Habanero field in December 2012 and our Medusa and shelf properties in the fourth quarter of 2013, drove the revenue decline. Also contributing to the production decline were 20 days of down time for scheduled downstream pipeline maintenance at our Medusa field in the second quarter of 2013, approximately five days of production downtime at our key producing Permian Basin fields in the fourth quarter of 2013 due to severe winter weather causing electricity outages and the extended curtailment of trucking capacity to transport offtake and due to normal and expected declines from other producing wells. Collectively, these declines were offset by the 222 MBbls increase in our oil production from our Permian properties.
For the year ended December 31, 2012, oil revenues of $96.6 million decreased $4.4 million, or 4%, compared to revenues of $101.0 million for the year ended December 31, 2011. A decrease in commodity prices and production resulted in decreased oil revenue. The average price realized decreased 2% to $98.86 per barrel compared to $101.34 for the same period of 2011. Similarly, production decreased by 2% to 977 MBbls compared to 996 MBbls during the same period in 2011. Oil prices for production from our two deepwater fields are adjusted and reflect a premium over NYMEX pricing based on Mars WTI differential for Medusa production and Bonita WTI differential for Habanero production. Production decreases relate primarily to the down-time at the Habanero and Medusa fields and the normal and expected declines from our other offshore properties. These production declines were offset by production from our new Permian wells, 22 vertical and two horizontal, brought onto production during 2012.
Callon Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Natural Gas Revenue
For the year ended December 31, 2013, natural gas revenues of $13.6 million represented a decrease of 4%, or $0.5 million, compared to natural gas revenues of $14.1 million for the year ended December 31, 2012. While the average realized price increased 15%, a 16% decrease in production reduced total revenue. The production declines were primarily attributable to the shut-in of production of our Mobile Bay 908 property, the sale of our offshore fields, the sale of our Haynesville well in the fourth quarter of 2013 as well as normal and expected declines from our existing wells. Offsetting these declines was a 248 MMcf increase in horizontal well production from our Permian properties.
For the year ended December 31, 2012, natural gas revenues of $14.1 million represented a decrease of 47%, or $12.5 million, when compared to natural gas revenues of $26.7 million for the year ended December 31, 2011. Natural gas production decreased 29%, driven primarily by down time at our Haynesville well, which was shut-in for 70 days during the first quarter of 2012 due to well interference from an offsetting well, and due to down time at our East Cameron 257 well, which was suspended in the fourth quarter of 2011 due to a natural gas leak in an upstream section of the Stingray Pipeline that transports production volumes from the field. Also contributing to the decline was down-time at our Habanero and Medusa fields and normal and expected declines in natural gas production from our offshore and Haynesville wells. In addition to production decreases, the average realized price decreased 25% to $3.94 per Mcf compared to an average realized price of $5.25 per Mcf in 2011. Our natural gas prices on an MMBtu equivalent basis exceeded the related NYMEX prices primarily due to the value of the NGLs in our natural gas stream, primarily from our Permian basin and deepwater production.
Operating Expenses
Principal components of our cost structure
Lease operating expenses. These are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workover expenses related to our oil and natural gas properties.
Production taxes. Production taxes include severance and ad valorem taxes. 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. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and gas properties.
Depreciation, depletion and amortization. Under the full cost accounting method, we capitalize 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 unproved properties and major development projects for which proved reserves cannot yet be assigned, 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.
General and administrative. These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other fees for professional services and legal compliance.
Accretion expense. The Company is required to record its estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligations and reported as accretion expense within operating expenses in the consolidated statements of operations.
Callon Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Lease Operating Expenses (LOE)
For the year ended December 31, 2013, LOE of $19.8 million decreased 15%, or $3.6 million, compared to $23.3 million for the year ended December 31, 2012. The decrease was primarily due to $3.4 million of remediation costs on our Haynesville well in 2012, for which we had no similar costs in 2013, and an estimated decrease of $3.2 million of LOE resulting from the previously discussed sale of our interests in Habanero, Medusa, the Medusa Spar LLC, our Haynesville property and substantially all our remaining shelf properties. These decreases were partially offset by $3.0 million in LOE costs related to the growth in Permian production and operations, including an increase in workover expenses associated with accelerated horizontal well activity.
For the year ended December 31, 2012, LOE of $23.3 million increased 28%, or $5.0 million, compared to $18.3 million for the year ended December 31, 2011. The increase was primarily due to $3.0 million in costs related to growth in the number of wells producing from Permian Basin properties and $3.3 million in remediation work at our Haynesville well in 2012 for which we had no similar costs in 2011. These increases were partially offset by a $1.3 million decline in LOE for our deepwater properties due to lower throughput charges as a result of reduced production volumes.
Production Taxes
For the year ended December 31, 2013, production taxes of $4.1 million increased 28%, or $0.9 million, compared to $3.2 million for the year ended December 31, 2012. The increase was predominantly attributable to an increase of onshore production subject to these taxes and a decline in offshore production, resulting from the sale of our Gulf of Mexico position in 2013, which is exempt from production taxes.
For the year ended December 31, 2012, production taxes of $3.2 million increased 56%, or $1.2 million, compared to $2.1 million for the year ended December 31, 2011. The increase was predominantly attributable to an increased proportion of onshore production subject to these taxes relative to offshore production, which was predominantly exempt from production taxes.
Callon Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Depreciation, Depletion and Amortization (DD&A)
For the year ended December 31, 2013, DD&A of $31.12 per BOE was relatively flat compared to $31.56 per BOE for the year ended December 31, 2012.
DD&A for the year ended December 31, 2012 increased 19% per BOE to $31.56 per BOE compared to $26.42 per BOE for the year ended December 31, 2011. Increases in the DD&A rate are attributable to our planned exploration and development expenditures related to our onshore reserve development including the ongoing onshore development cost increases in the Permian Basin area.
General and Administrative, net of amounts capitalized (G&A)
G&A remained relatively flat at $20.5 million (including $6.4 million non-cash) for the year ended December 31, 2013 compared to $20.4 million (including $4.7 million non-cash) for the same period of 2012. The $0.1 million increase was due to an increase in non-cash charges of $1.7 million related to incentive compensation share-based instruments offset by a $1.6 million decrease primarily related to non-recurring employee-related expenses including early retirement and severance expense incurred in 2012. The non-cash portions primarily relate to our liability-based incentive compensation share based instruments (see Notes 7 and 8 ) and to depreciation and amortization expense (see Note 2).
For the year ended December 31, 2012, G&A, increased $3.7 million, or 22%, to $20.4 million (including $4.7 million non-cash) from $16.6 million (including $3.2 million non-cash) for the same period of 2011. The increase is due mainly to $1.6 million in costs for non-recurring employee-related expenses including early retirement and severance expense for which we had no expense during 2011. Additionally, we incurred an increase in non-cash charges of $1.2 million related to incentive compensation share-based instruments awarded during 2012. The remaining increase related primarily to higher compensation-related expenses including the costs associated with employing staff to support our onshore growth and 100% operated Permian production, as well as relocation and related costs.
Accretion Expense (ARO)
Accretion expense related to our asset retirement obligation decreased 21% for the year ended December 31, 2013 compared to the same periods of 2012. Accretion expense correlates directionally with the Company’s ARO which was $6.7 million at December 31, 2013 versus $13.3 million at December 31, 2012. See Note 11 for additional information regarding the Company’s ARO.
For the year ended December 31, 2012, accretion expense decreased 4% for the year ended December 31, 2012 compared to the same periods of 2011. At December 31, 2012, our ARO of $13.3 million was lower than the $13.9 million ARO at December 31, 2011.
Impairment of Other Property and Equipment
During 2012 and 2013, the Company recorded a write-down of the value of certain assets acquired in 2011 as part of a settlement reached with a former joint interest partner on a deepwater project. For information concerning the impairment of these assets, please see Note 13 to the Consolidated Financial Statements.
Other (Income) Expense
Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions 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. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense. The amortization of the deferred credit related to our 13% Senior Notes is recorded as an offset to interest expense.
Gain/Loss on derivative instruments. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the price of oil. This amount represents the (i) gain (loss) related to derivatives, net of settlement that relate to our open derivative contracts as commodity prices change and commodity derivative contracts expire or new ones are entered into and (ii) gains (losses) on derivatives, settled that is equal to the summation of gains and losses on positions that have settled within the period. We provide a reconciliation of the these components of the gain/loss on derivative contracts in Note 5.
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
Callon Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations
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 deferred tax assets will not be realized.
Interest Expense
Interest expense on Callon’s debt obligations decreased 3.0 million to $6.1 million for the year ended December 31, 2013 compared to $9.1 million for the same period of 2012. The decrease was related primarily to an additional $2.3 million of interest capitalized in 2013 versus 2012, to approximately $0.3 million of reduced interest payments attributable to the redemption of $48.5 million principal of the Company’s Senior Notes in December 2013 and to $0.1 million of additional deferred credit amortization recognized in 2013 compared with 2012. The additional capitalized interest was related to a higher balance year-over-year in average unevaluated oil and natural gas properties following the purchase of additional unevaluated acreage with exploration costs in the Permian Basin.
Interest expense on Callon’s debt obligations decreased 22% to $9.1 million for the year ended December 31, 2012 compared to $11.7 million for the same period of 2011. The decrease was related primarily to the redemption of $10 million principal of Senior Notes during June 2012 in addition to a $1.5 million increase in capitalized interest compared to 2011, partially offset by interest expense related to increased borrowings under our Credit Facility and decreases in the deferred credit amortization. The increase in capitalized interest was related to a higher balance year-over-year in average unevaluated oil and natural gas properties, mentioned above.
(Gain) Loss on Early Extinguishment of Debt
During December 2013, the Company redeemed $53.8 million carrying value of its Senior Notes using a portion of the proceeds from the Company’s May 2013 preferred equity offering. The $53.8 million of carrying value included $48.5 million of principal value and $5.3 million of unamortized deferred credit. The Company recognized a net gain of $3.7 million on the early extinguishment of debt, comprised of the recognition of $5.3 million in deferred credit, offset by $1.6 million of redemption expenses. See Note 4 for additional information concerning the gain on early extinguishment of debt.
During June 2012, the Company redeemed $10 million of its Senior Notes with a carrying value of $11.6 million, including $1.6 million of the Senior Notes’ deferred credit. The Company recognized a net gain of $1.4 million on the early extinguishment of debt, comprised of the recognition of $1.6 million in deferred credit, offset by $0.2 million of redemption expenses.
Gain on Acquired Equipment
See Note 13 for additional information concerning the gain on acquired equipment.
Callon Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Loss (Gain) on Derivative Contracts
Beginning in 2012, the Company elected to no longer designate its derivative contracts as accounting hedges. For the year ended December 31, 2013, net losses on mark-to-market derivative instruments, net of settlements were $1.4 million, compared to $1.7 million gain in 2012. See Notes 5 and 6 for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation.
Income Tax Expense (Benefit)
The income tax expense of $3.1 million in 2013 resulted primarily from pre-tax income earnings of $7.4 million. The effective tax rate of 42% in 2013 and 47% in 2012 differed from the federal income tax rate of 35% primarily due to the effect of state taxes, non-deductible compensation under Section 162(m) and restricted stock offset by percentage depletion. See Note 10 for a discussion of our effective tax rate. Prior to 2012, we carried a full valuation allowance against our net deferred tax asset. The income tax benefit of $69.3 million in 2011 resulted primarily from the reversal of the valuation allowance established in 2008 against our net deferred tax assets as we achieved income on an aggregate basis for a cumulative three-year period and expect to generate the taxable income necessary to fully utilize the deferred tax assets prior to their expiration. For additional information, see Note 11 to the Consolidated Financial Statements.
Preferred Stock Dividends
Preferred Stock dividends for the year ended December 31, 2013 increased $4.6 million compared to the same period of 2012 in which we had no dividend expense. The expense is reflective of the Preferred Stock being outstanding only since its issuance on May 30, 2013, resulting in a reduced stub period payment during the second quarter of 2013.
Summary of Significant Accounting Policies and Critical Accounting Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been use. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under GAAP. We also describe the most significant estimates and assumptions we make in applying these policies. See Note 2 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K for a discussion of additional accounting policies and estimates made by management.
Property and Equipment
The Company utilizes the full-cost method of accounting for its oil and natural gas properties whereby all costs incurred in connection with the acquisition, exploration and development of oil and natural gas reserves, including certain overhead costs, are capitalized into the “full-cost pool.” The amounts capitalized into the full-cost pool are depleted (charged against earnings) using the unit-of-production method. The full-cost method of accounting for our proved oil and natural gas properties requires that the Company makes estimates based on its assumptions of future events that could change. These estimates are described below.
Depreciation, Depletion and Amortization (DD&A) of Oil and Natural Gas Properties
The Company calculates depletion by using the depletable base, equal to the net capitalized costs in our full-cost pool plus estimated future development costs, and the estimated net proved reserve quantities. Capitalized costs added to the full-cost pool include the following:
•
costs of drilling and equipping productive wells, dry hole costs, acquisition costs of properties with proved reserves, delay rentals and other costs related to exploration and development of our oil and natural gas properties;
•
payroll costs including the related fringe benefits paid to employees directly engaged in the acquisition, exploration and/or development of oil and natural gas properties as well as other directly identifiable general and administrative costs
Callon Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations
associated with such activities. Such capitalized costs do not include any costs related to the production of oil and natural gas or general corporate overhead;
•
costs associated with unevaluated properties, those lacking proved reserves, are excluded from the depletable base. These unevaluated property costs are added to the depletable base at such time as wells are completed on the properties, the properties are sold or the Company determines these costs have been impaired. The Company’s determination that a property has or has not been impaired (which is discussed below) requires assumptions about future events;
•
estimated costs to dismantle, abandon and restore properties that are capitalized to the full-cost pool when the related liabilities are incurred (see also the discussion below regarding Asset Retirement Obligations);
•
estimated future costs to develop proved properties are added to the full-cost pool for purposes of the DD&A computation. The Company uses assumptions based on the latest geologic, engineering, regulatory and cost data available to it to estimate these amounts. However, the estimates made are subjective and may change over time. The Company’s estimates of future development costs are reviewed at least annually and as additional information becomes available; and
•
capitalized costs included in the full-cost pool plus estimated future development costs are depleted and charged against earnings using the unit-of-production method. Under this method, the Company estimates the proved reserves quantities at the beginning of each accounting period. For each BOE produced during the period, the Company records a depletion charge equal to the amount included in the depletable base (net of accumulated depreciation, depletion and amortization) divided by our estimated net proved reserve quantities.
Because the Company uses estimates and assumptions to calculate proved reserves (as discussed below) and the amounts included in the depletable base, our depletion rates may materially change if actual results differ from these estimates.
Ceiling Test
Under the full cost method of accounting, the Company compares, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (excluding cash flows related to estimated abandonment costs), to the net capitalized costs of proved oil and natural gas properties net of related deferred taxes. The Company refers to this comparison as a “ceiling test.” If the net capitalized costs of proved oil and natural gas properties exceed the estimated discounted (at 10%) future net cash flows from proved reserves, the Company is required to write-down the value of its oil and natural gas properties to the value of the discounted cash flows. Estimated future net cash flows from proved reserves are based on a twelve-month average pricing assumption and include consideration of existing cash flow hedges. Given the volatility of oil and natural gas prices, it is reasonably possible that the Company’s estimates of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. If oil and natural gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and natural gas properties could occur in the future. See Notes 2 and 12 for additional information regarding the Company’s oil and natural gas properties.
Estimating Reserves and Present Value of Estimated Future Net Cash Flows
Estimates of quantities of proved oil and natural gas reserves, including the discounted present value of estimated future net cash flows from such reserves at the end of each quarter, are based on numerous assumptions, which are likely to change over time. These assumptions include:
•
the prices at which the Company can sell its oil and natural gas production in the future. Oil and natural gas prices are volatile, but we are required to assume that they remain constant, using the twelve-month average pricing assumption. In general, higher oil and natural gas prices will increase quantities of proved reserves and the present value of estimated future net cash flows from such reserves, while lower prices will decrease these amounts; and
•
the costs to develop and produce the Company’s reserves and the costs to dismantle its production facilities when reserves are depleted. These costs are likely to change over time, but we are required to assume that they remain constant. Increases in costs will reduce estimated oil and natural gas quantities and the present value of estimated future net cash flows, while decreases in costs will increase such amounts.
Changes in these prices and/or costs will affect the present value of estimated future net cash flows more than the estimated quantities of oil and natural gas reserves for the Company’s properties that have relatively short productive lives.
Callon Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations
In addition, the process of estimating proved oil and natural gas reserves requires that the Company’s independent and internal reserve engineers exercise judgment based on available geological, geophysical and technical information. We have described the risks associated with reserve estimation and the volatility of oil and natural gas prices under “Risk Factors.”
Sales of oil and natural gas properties are accounted for as adjustments to the net full cost pool with no gain or loss recognized unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.
Unproved Properties
Costs, including capitalized interest, associated with properties that do not have proved reserves are excluded from the depletable base, and are included in the line item “Unevaluated properties excluded from amortization.” Unproved property costs are transferred to the depletable base when wells are completed on the properties or the properties are sold. In addition, the Company is required to determine whether its unproved properties are impaired and, if so, include the costs of such properties in the depletable base. The Company determines whether an unproved property is impaired by periodically reviewing its exploration program on a property-by-property basis. This determination may require the exercise of substantial judgment by management.
Asset Retirement Obligations
We are required to record its estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-life assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligation and reported as accretion expense within operating expenses in the Consolidated Statements of Operations. See Note 11 for additional information.
Derivatives
To manage oil and natural gas price risk on a portion of our planned future production, we have historically utilized commodity derivative instruments (including collars, swaps, puts, and other structures) on approximately 50% of our projected production volumes in any given year. We do not use these instruments for trading purposes. Settlement of derivative contracts are generally based on the difference between the contract price and prices specified in the derivative instrument and a NYMEX price or other cash or futures index price.
Beginning in 2012, we elected to no longer designate derivative contracts executed after January 1, 2012 as accounting hedges under FASB ASC 815-20-25. As such and beginning with derivative contracts executed during 2012, all derivative positions are carried at their fair value on the balance sheet and are marked-to-market through earnings at the end of each period. Gains and losses on derivatives that are not designated as hedges are recorded in earnings as a component of gain (loss) on derivative contracts. Within gain (loss) on derivative contracts line in the statement of operations are gains (losses) on derivatives, net of settlement and gains (losses) on derivatives, settled.
Derivative contracts that were entered into at and prior to December 31, 2011 were accounted for as cash flow hedges, and were recorded at fair market value on its consolidated balance sheet. Changes in fair value were recorded through other comprehensive income (loss), net of tax, in stockholders’ equity. The changes in fair value related to ineffective derivative contracts were recognized as derivative expense (income). The estimated fair value of our derivative contracts is based upon closing exchange prices on NYMEX and in the case of collars and floors, the time value of options. For additional information regarding derivatives and their fair values, see Notes 5 and 6 to the Consolidated Financial Statements and Part II, Item 7A
ITEM 7A. Quantitative and Qualitative Disclosures about Market Risks
We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative instruments.
Commodity Price Risk
The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our oil and natural gas, which have historically been very volatile due to unpredictable events such as economic growth or retraction, weather and climate, changes in supply and government actions. Oil and natural gas price declines and volatility could adversely affect the Company’s revenues, cash flows and profitability. Price volatility is expected to continue. Using the Company’s annual sales volumes for 2013, excluding the effects of the Company’s hedging program, a 10% decline in the NYMEX price of oil and natural gas would have reduced our revenues by approximately $8.9 million and $1.2 million, respectively.
While the Company does not enter into derivative transactions for speculative purposes, the Company sometimes utilizes price collars, swaps, puts and other structures to reduce the risk of changes in oil and natural gas prices. Under a collar arrangements, no payments are due by either party as long as the market price is above the floor price and below the ceiling price set in the collar. If the price falls below the floor, the counterparty to the collar pays the difference to Callon, and if the price rises above the ceiling, Callon pays the difference to the counterparty. Fixed price swaps reduce the Company’s exposure to decreases in commodity prices, while simultaneously limiting the benefit the Company might otherwise have received from any increases in commodity prices. The Company’s derivatives policy also allows Callon to, at its discretion, purchase or sell puts. Purchased puts reduce the Company’s exposure to decreases in prices of the hedged commodity while allowing realization of the full benefit from any increases those prices. If the commodity price falls below the put price, the counter-party pays the difference to Callon. Conversely, sold puts expose the Company to risk whereby Callon would pay its counter-party if prices fall below the put price. See Note 5 to the Consolidated Financial Statements for a description of our hedged position at December 31, 2013.
Interest Rate Risk
On December 31, 2013, the majority of the Company’s debt consisted of its fixed-rate 13% Senior Notes. However, we are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facility and our Second Lien Facility into which we entered during March 2014. As of December 31, 2013, the weighted average interest rate on our Credit Facility borrowings was 2.9%. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our net income of approximately $0.2 million based on the $22 million outstanding in the aggregate under our Credit Facility on December 31, 2013.
Counterparty and Customer Credit Risk
Our principal exposures to credit risk are through receivables resulting from derivatives financial contracts, joint interest receivables and the receivables from the sale of our oil and natural gas production, which we market to energy marketing companies.
At December 31, 2013 our receivables resulting from derivative financial contracts was approximately $0.1 million. Our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. The counterparties on our derivative instruments currently in place are lenders under our revolving credit facility. We are likely to enter into additional derivative instruments with these or other lenders under our revolving credit facility, representing institutions with an investment grade ratings. We have existing International Swap Dealers Association Master Agreements (“ISDA Agreements”) with our derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of set off upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. At December 31, 2013 we had a net derivative asset position of $0.1 million and a net derivative liability position of $1.1 million.
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 intend to drill. We have little ability to control whether these entities will participate in our wells. At December 31, 2013 our joint interest receivables were approximately $4.4 million.
We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We do not require any of our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. For the year ended December 31, 2013, three purchasers accounted for more than 10% of our revenue: Enterprise Crude Oil, LLC (38%); Shell Trading Company (31%); and Plains Marketing, L.P. (15%). At December 31, 2013 our receivables from the sale of our oil and natural gas production were approximately $13.2 million in total.
ITEM 8.
ITEM 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of
Callon Petroleum Company
We have audited the accompanying consolidated balance sheets of Callon Petroleum Company as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Callon Petroleum Company as of December 31, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Callon Petroleum Company’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated March 12, 2014, expressed an unqualified opinion thereon.
/s/Ernst & Young LLP
New Orleans, Louisiana
March 12, 2014
CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
The accompanying notes are an integral part of these financial statements.
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
The accompanying notes are an integral part of these financial statements.
CALLON PETROLEUM COMPANY
CONSOLIDATE STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
The accompanying notes are an integral part of these consolidated financial statements.
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands)
The accompanying notes are an integral part of these financial statements.
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
The accompanying notes are an integral part of these financial statements.
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
NOTE 1 - Description of Business and Basis of Presentation
Callon Petroleum Company is an independent oil and natural gas company established in 1950, which has been focused on building reserves and production both onshore and offshore through efficient operations and low finding and development costs. In 2013, the Company completed the onshore strategic repositioning it initiated in 2009, shifting its operations from the offshore waters in the Gulf of Mexico to the Permian Basin region in Texas. The Company has built seasoned technical and operational teams with extensive experience in the Permian Basin to manage and progress its growth plan. In the fourth quarter of 2012, Callon sold its interest in its deepwater Habanero field. Similarly, in the fourth quarter of 2013, the Company sold its interest in its only remaining deepwater property, the Medusa field, including the sale of the Medusa Spar facility and substantially all remaining offshore shelf properties. These transactions completed the Company’s long-term strategic goal of becoming an onshore operator with an asset base concentrated in the Permian Basin.
The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company partially owned by a member of current management. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise.
The Consolidated Financial Statements include the accounts of the Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also includes the subsidiaries Callon Offshore Production, Inc. and Mississippi Marketing, Inc. All intercompany accounts and transactions have been eliminated. Certain prior year amounts have been reclassified to conform to presentation in the current year. To the extent these amounts are material, we have either footnoted them within the Company’s disclosures or have noted the items within this footnote. The Company reclassified on its 2012 and 2011 Consolidated Statements of Operations $3,224 and $2,062, respectively, from “Lease operating expenses” to “Production taxes” to conform to current year presentation.
Unless otherwise indicated, all amounts included within the footnotes to the financial statements are presented in thousands, except for share, well, acreage and per-derivative instrument data.
NOTE 2 - Summary of Significant Accounting Policies
A.
Use of Estimates
The preparation of financial statements in conformity with United States generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
B.
Cash and Cash Equivalents
The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
C.
Accounts Receivable
Accounts receivable consists primarily of accrued oil and natural gas production receivables. The balance in the reserve for doubtful accounts netted within accounts receivable was $73 and $34 at December 31, 2013 and 2012, respectively. During 2013, 2012, and 2011 the Company recorded $45, $0 and $(281), respectively of bad debt expense. The negative bad debt expense in 2011 relates to the collection of an amount charged to bad debt expense during 2010.
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
D.
Revenue Recognition and Natural Gas Balancing
The Company recognizes revenue under the entitlement method of accounting. Under this method, revenue is deferred for deliveries in excess of the Company’s net revenue interest, while revenue is accrued for the undelivered volumes. Production imbalances are generally recorded at the lower of cost or market. The revenue we receive from the sale of NGLs is included in natural gas sales. Natural gas balancing receivables were $71 and $93 as of 2013 and 2012, respectively. Natural gas balancing payables were $126 and $653 as of 2013 and 2012, respectively.
E.
Major Customers
The Company’s production is generally sold on month-to-month contracts at prevailing prices. The following table identifies customers to whom it sold a greater than 10% of its total oil and natural gas production during each of the years ended:
Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on its ability to market future oil and natural gas production.
F.
Oil and Natural Gas Properties
The Company uses the full-cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as property and equipment. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized in accordance with asset retirement obligation accounting guidance. Costs capitalized also include any internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any costs related to production, general corporate overhead or similar activities. The Company capitalized $14,753, $13,331 and $11,857 of these internal costs during 2013, 2012 and 2011, respectively.
When applicable, proceeds from the sale or disposition of oil and natural gas properties are accounted for as a reduction to capitalized costs unless the sale would significantly alter the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized in income.
Costs of oil and natural gas properties, including future development costs, which have proved reserves and properties which have been determined to be worthless, are depleted using the unit-of-production method based on proved reserves. Excluded from this amortization are costs associated with unevaluated properties, including capitalized interest on such costs. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or management determines that these costs have been impaired.
Under the full-cost accounting rules of the SEC, 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 generally 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 “ceiling” is exceeded. See Note 12 for additional information regarding the Company’s oil and natural gas properties.
Upon the acquisition or discovery of oil and natural gas properties, the Company estimates the future net costs to dismantle, abandon and restore the property by using available geological, engineering and regulatory data. Such cost estimates are periodically updated for changes in conditions and requirements. In accordance with asset retirement obligation guidance issued
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
by the FASB, such costs are capitalized to the full-cost pool when the related liabilities are incurred. In accordance with SEC’s rules, assets recorded in connection with the recognition of an asset retirement obligation are included as part of the costs subject to the full-cost ceiling limitation. The future cash outflows associated with settling the recorded asset retirement obligations are excluded from the computation of the present value of estimated future net revenues used in determining the full-cost ceiling amount.
G.
Other Property and Equipment
The Company depreciates its other property and equipment of $7,255 and $6,424 at December 31, 2013 and 2012, respectively, using the straight-line method over estimated useful lives of three to 20 years. Depreciation expense of $750, $760 and $645 relating to other property and equipment was included in general and administrative expenses in the Company’s consolidated statements of operations for the years ended December 31, 2013, 2012 and 2011, respectively. The accumulated depreciation on other property and equipment was $13,240 and $13,238 as of December 31, 2013 and 2012, respectively. As discussed in Note 13, during 2013, the Company recorded an impairment charge to reduce to zero the carrying values of its assets held for sale. The Company reviews its other property and equipment for impairment when indicators of impairment exist.
H.
Capitalized Interest
The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization (e.g. unevaluated properties). Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Capitalized interest cannot exceed gross interest expense. During the years ended December 31, 2013, 2012 and 2011, the Company capitalized $4,410, $2,109 and $573 of interest expense.
I.
Asset Retirement Obligations
The Company is required to record its estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligations and reported as accretion expense within operating expenses in the consolidated statements of operations. See Note 11 for additional information.
J.
Derivatives
The Company’s derivative contracts executed prior to 2012 were designated as cash flow hedges, and were recorded at fair market value with the changes in fair value recorded net of tax through other comprehensive income (loss) (“OCI”) in stockholders’ equity. Ineffective derivative contracts or ineffective portions of contracts designated as cash flow hedges were recognized as derivative expense (income). The last of the Company’s derivative contracts designated as cash flow hedges expired on December 31, 2012. Derivative contracts executed during 2013 and outstanding as of December 31, 2013 were not designated as accounting hedges, and are carried on the balance sheet at their fair market value. Changes in the fair value of derivative contracts not designated as accounting hedges are reflected in earnings as a gain or loss on derivative contracts. See Notes 5 and 6 for additional information regarding the Company’s derivative contracts.
K.
Income Taxes
Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties for financial reporting purposes and income tax purposes. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards, statutory depletion carryforward and tax credit carryforwards, net of a valuation allowance. A valuation allowance is provided for that portion, if any, of the asset for which it is deemed more likely than not that it will not be realized. See Note 10 for additional information.
L.
Share-Based Compensation
The Company grants to directors and employees stock options, restricted stock awards (“RS awards”), and restricted stock unit awards (“RSU awards”) that may be settled in cash or common stock at the option of the Company and RSU awards that may only be settled in cash (“Cash-settleable RSU awards”).
Stock Options. For stock options the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value as calculated using the Black-Scholes option pricing model and recognized straight-line over the vesting period (generally three years).
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
RS awards, RSU awards and Cash-settleable RSU awards. For RS and RSU awards that the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value and recognized straight-line over the vesting period (generally three years). For Cash-settleable RSU awards that the Company expects or is required to settle in cash, share-based compensation expense is based on the fair value remeasured at each reporting period as calculated using a Monte Carlo pricing model, because vesting of these awards is subject to a market condition, with the estimated value recognized over the vesting period (generally three years).
M.
Statements of Cash Flows Supplemental Information
During the three year period ended 2013, the Company paid no federal income taxes. During the years ended December 31, 2013, 2012 and 2011, the company made cash interest payments of $13,189, $13,920 and $14,922, respectively.
N.
Investment in Medusa Spar LLC
During the fourth quarter of 2013, the Company closed on the sale of its 15.0% working interest in the Medusa field, its 10.0% membership interest in Medusa Spar LLC (“LLC”), and substantially all of its remaining Gulf of Mexico shelf properties. Prior to the sale, the Company’s ownership interest in the LLC was accounted for under the equity method of accounting for investments. The LLC held a 75% undivided ownership interest in the deepwater spar production facilities at the Medusa field in the Gulf of Mexico and earned a tariff based upon production volume throughput from the Medusa area. The Company was obligated to process through the spar production facilities its share of production from the Medusa field and any future discoveries in the area. The balance of the LLC was owned by Oceaneering International, Inc. and Murphy Oil Corporation. See Note 12 for additional information on the Medusa divestiture.
O.
Consolidation of Variable Interest Entities
In June 2009, the FASB issued an accounting standard which became effective for and was adopted by the Company on January 1, 2010. Upon adoption, the Company reevaluated its interest in its subsidiary, Callon Entrada. Based on the evaluation performed, management concluded that a VIE reconsideration event had taken place resulting in the determination that Callon Entrada is a VIE, for which the Company is not the primary beneficiary. Therefore, effective January 1, 2010, Callon Entrada was deconsolidated from the consolidated financial statements of the Company. During the second quarter of 2011 and through the formal execution of a wind-down agreement with its former joint interest partner in the Entrada deepwater project, which resulted in Callon gaining the power to direct the activities of Callon Entrada, the Company became the primary beneficiary of Callon Entrada. Consequently, effective April 29, 2011, Callon Entrada was reconsolidated in the Company’s financial statements. Callon Entrada was later dissolved in 2011.
P.
Earnings per Share (EPS)
The Company’s basic EPS amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS, using the treasury-stock method, reflects the potential dilution caused by the exercise of all options and vesting of all restricted stock and restricted stock units settleable in shares.
Q.
Recent Accounting Pronouncements
From time to time, new accounting pronouncements are issued by FASB that are adopted by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption.
In February 2013, the Financial Accounting Standards Board issued an Accounting Standards Update (ASU) that clarified the reclassification requirements from accumulated other comprehensive income to net income and required disclosure of amounts reclassified out of accumulated other comprehensive income by component. In addition, it requires that the Company present either on the face of its financial statements or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income, but only if the amount is reclassified in its entirety to net income in the same reporting period. For amounts not reclassified in their entirety to net income, the Company is required to cross-reference to the related note on the face of the financial statements for additional information. Callon adopted this guidance effective January 1, 2013, which did not have a material impact on its financial statements.
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
NOTE 3 - Earnings (loss) per Share
Basic earnings (loss) per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of non-vested restricted shares and unexercised options outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. A reconciliation of the basic and diluted net income per share computation is as follows (in thousands, except per share amounts):
(1)
Because the Company reported a loss for the year ended December 31, 2013, no unvested stock awards were included in computing loss per share because the effect was anti-dilutive.
NOTE 4 - Borrowings
Senior Secured Revolving Credit Facility (the “Credit Facility”)
The Company’s $200,000 Credit Facility, for which Regions Bank serves as the Administrative Agent, matures March 15, 2016 and includes Citibank, NA, IberiaBank, Whitney Bank and OneWest Bank, FSB as participating lenders. The Company’s Credit Facility had an approved borrowing base at December 31, 2013 of $83,000. The Credit Facility was secured by mortgages covering the Company’s major producing fields. As of December 31, 2013, the balance outstanding on the Credit Facility was $22,000 with an interest rate of 2.92%, calculated as the London Interbank Offered Rate (LIBOR), plus a tiered rate ranging from 2.5% to 3.0%, which is determined by utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum on the unused portion of the borrowing base, which is payable quarterly.
Subsequent to December 31, 2013, the Company amended its existing Credit Facility as discussed below. Additionally, the Company executed the Second Lien Facility also discussed below.
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
Amended Credit Facility (“the Amended Credit Facility”)
On March 11, 2014, the Company entered into the Fifth Amended and Restated Credit Agreement million with JPMorgan Chase Bank, National Association as Administrative Agent.
The Amended Credit Facility includes the following key provisions:
•
$500,000 notional amount, with an initial borrowing base of $95,000;
•
Maturity date of March 11, 2019;
•
First redetermination scheduled with an effective date of May 30, 2014, with subsequent redeterminations occurring every six months beginning on September 1, 2014;
•
Pricing grid providing from Eurodollar-based draws ranging from LIBOR plus 1.75% to 2.75% depending on utilization;
•
A quarterly commitment fee equal to 0.5% per year of the unused portion of the borrowing base; and
•
Secured by mortgages covering all major producing fields.
The Amended Credit Facility contains various affirmative and restrictive covenants.
Second Lien Term Loan Facility (the “Second Lien Facility”)
In conjunction with the Amended Credit Facility, the Company entered into the Second Lien Facility in an aggregate amount of up to $125,000 with JPMorgan Chase Bank, National Association as Administrative Agent. The Second Lien Facility is structured as a multiple advance term loan facility, with initial commitments of $100,000. If any portion of the committed Second Lien Facility remains undrawn on the first anniversary of the closing date, then the unfunded commitments under the Second Lien Facility, if any, will terminate on such date.
The Second Lien Facility includes the following key provisions:
•
$125,000 master note, with initial commitments $100,000 and additional availability of $25,000 with consent of 66 2/3% of the lenders and compliance with financial covenants after giving effect to such increase;
•
Maturity date of September 11, 2019;
•
No mandatory prepayments unless new debt is issued;
•
Prepayable at any time. The prepayment premium shall be applicable to the amount of the applicable prepayment multiplied by (i) 102% if such prepayment event occurs prior to the first anniversary of the Closing Date and (ii) 101% if such prepayment event occurs on or after the first but prior to the second anniversary of the Closing Date. No such prepayment premium shall be payable for prepayments made on or after the second anniversary of the closing date;
•
Interest expense at a rate of LIBOR plus 7.75%, calculated on a per annum basis;
•
A commitment fee equal to 0.5% calculated on a per annum basis on the unused portion of the initial commitment amount until March 11, 2015;
•
The amounts funded on the initial draw date shall be issued with an original issue discount of 1.00% and each subsequent draw shall be subject to the same 1.00% original issue discount on the drawn amount, applied on the date such draw is funded; and
•
Secured by junior liens on properties mortgaged under the Amended Credit Facility, subject to an intercreditor agreement.
The Second Lien Facility contains various affirmative and restrictive covenants.
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
13% Senior Notes due 2016 (the “Senior Notes”) and Deferred Credit
As of December 31, 2013, the Company had principal outstanding of $48,481 related to its 13% Senior Notes. The interest coupon is payable on the last day of each quarter. Certain of the Company’s subsidiaries guarantee the Company’s obligations under the unsecured Senior Notes. The subsidiary guarantors are 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations, and any subsidiaries of the parent company other than the subsidiary guarantors are minor. Upon issuing the Senior Notes in November 2009, the Company reduced the carrying amount of the Old Notes by the fair value of the common and preferred stock issued in the amount of $11,527. The $31,507 difference between the adjusted carrying amount of the Old Notes and the face value of the Senior Notes was recorded as a deferred credit, which is being amortized as a reduction in interest expense over the life of the Senior Notes at an 8.5% effective interest rate.
The following table summarizes the Company’s deferred credit balance at December 31, 2013:
(a)
Of the amount recorded as amortization during the current year, $3,165 was recorded as a reduction of interest expense and $5,275 (discussed below) was recorded as a component of the gain on early extinguishment of debt.
Using a portion of the proceeds from the sale of our interest in Medusa on December 17, 2013, the Company redeemed $48,481 of its Senior Notes, which resulted in a net $3,696 gain on the early extinguishment of debt. The gain represents the difference between the $50,057 paid (inclusive of $1,576 of redemption expenses, primarily the call premium) for Senior Notes with a carrying value of $53,756 (inclusive of the $5,275 of accelerated deferred credit amortization).
In June 2012, the Company redeemed $10,000 of its Senior Notes, which resulted in a net $1,366 gain on the early extinguishment of debt. The gain represents the difference between the $10,225 paid (inclusive of $225 of redemption expenses, primarily the call premium) for Senior Notes with a carrying value of $11,591 (inclusive of the $1,591 of accelerated deferred credit amortization).
In March 2011, the Company redeemed $31,000 of its Senior Notes using proceeds from its February 2011 equity offering, which resulted in a $1,974 gain on the early extinguishment of debt. The gain represents the difference between the $35,062 paid (inclusive of the$4,062 of redemption expenses, primarily the call premium) for Senior Notes with a carrying value of $37,004 (inclusive of the $6,004 of accelerated deferred credit amortization).
On March 11, the Company provided notice to holders of its outstanding Senior Notes that it expects to redeem those notes on April 11, 2014 using proceeds from the previously discussed Second Lien Facility. The redemption will result in the acceleration of the amortization of the remaining $5,267 of deferred credit as reflected in the table above.
Restrictive Covenants
The Indenture governing our Senior Notes and the Company’s Credit Facility contains various covenants including restrictions on additional indebtedness and payment of cash dividends. In addition, Callon’s Credit Facility contains covenants for maintenance of certain financial ratios. The Company was in compliance with these covenants at December 31, 2013.
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
NOTE 5 - Derivative Instruments and Hedging Activities
Objectives and Strategies for Using Derivative Instruments
The Company is exposed to fluctuations in oil and natural gas prices on the majority of its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil and natural gas production. The Company utilizes primarily a mix of collar, swap, put and call derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes.
Counterparty risk and offsetting
The use of derivative transactions exposes the Company to the risk that a counterparty will be unable to meet its commitments. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices. Counterparty credit risk is considered when determining a derivative instruments’ fair value; See Note 6 for additional information regarding fair value.
The Company executes commodity derivative transactions under master agreements that have netting provisions that provide for offsetting payables against receivables. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement.
Financial statement presentation and settlements
Settlements of the Company’s derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a New York Mercantile Exchange (“NYMEX”) price. The fair value of the Company’s derivative instruments, depending on the type of instruments, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. See Note 6 for additional information regarding fair value.
Beginning in 2012, the Company elected not to designate its executed derivative contracts, nor does it expect to designate future derivative contracts, as an accounting hedge under FASB ASC 815. Consequently, any derivative contract not designated as an accounting hedge will be carried at its fair value on the balance sheet and marked-to-market at the end of each period, with the change in value reflected as a gain or loss on the statement of operations. Gains and losses on derivatives that are not designated as hedges are recorded in earnings as a component of gain (loss) on derivative contracts. Within the gain (loss) on derivative contracts line of the statement of operations are gains (losses) on derivatives, net of settlement and gains (losses) on derivatives, settled.
Prior to 2012, the Company’s derivative contracts recorded on the Consolidated Balance Sheets were designated as cash flow hedges, and were recorded at fair market value with the changes in fair value recorded net of tax through OCI in stockholders’ equity. The cash settlements on effective derivative contracts were recorded as an increase or decrease in oil and natural gas sales.
The following table reflects the fair values of the Company’s derivative instruments for the periods presented (none of which were designated as hedging instruments under ASC 815):
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
The Company’s derivative contracts are subject to netting arrangements and, being representative of the way in which the contracts settle, are presented in the balance sheet at their fair values on a net basis based on the underlying commodity being hedged. The following presents the impact of this presentation to the Company’s recognized assets and liabilities at December 31, 2013:
Derivatives not designated as hedging instruments under ASC 815
For the periods indicated, the Company recorded the following related to its derivative instruments that were not designated as accounting hedges and are recorded in the Statement of Operations as gain or loss on derivative contracts:
Derivatives designated as hedging instruments under ASC 815
The table below presents the effect of the Company’s derivative financial instruments on the consolidated statements of operations as an increase (decrease) to oil and natural gas sales for the effective portion and as an increase (decrease) to other (income) expense for the ineffective portion and amounts excluded from effectiveness testing:
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
Derivative positions
In the first quarter of 2013, the Company monetized the remaining portion of its 2013 oil collar positions (for the period February - December 2013) of 40 Bbls per month. The proceeds from this transaction, combined with the proceeds from the sale of the below listed put for 30 Bbls per month, were used to finance the uplift in the oil swap for the period February - December 2013.
Listed in the table below are the outstanding oil and natural gas derivative contracts as of December 31, 2013:
(a)
The short natural gas call option, when combined with the Company’s long production position, represents a “covered call,” and creates a $4.75/MMbtu ceiling during the covered period.
Subsequent Event Activity:
Derivative contracts executed subsequent to December 31, 2013 include the following:
NOTE 6 - Fair Value Measurements
Fair value is defined within the accounting rules as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The rules established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels:
Level 1
Valuations consist of unadjusted quoted prices in active markets for identical assets and liabilities and has the highest priority.
Level 2
Valuations rely on quoted prices in markets that are not active or observable inputs over the full term of the asset or liability.
Level 3
Valuations are based on prices or third party or internal valuation models that require inputs that are significant to the fair value measurement and are less observable and thus have the lowest priority.
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
Fair Value of Financial Instruments
Cash, Cash Equivalents, and Short-Term Investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments.
Debt. The Company’s debt is recorded at the carrying amount on its Consolidated Balance Sheet. The fair value of Callon’s fixed-rate debt, which is valued using Level 2 inputs, is based upon estimates provided by an independent investment banking firm. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates.
The following table summarizes the respective carrying and fair values at:
(a)
2013 and 2012 fair values are calculated only in relation to the $48,481 and $96,961 face value outstanding of the 13% Senior Notes, respectively. The remaining $5,267 and $13,707, respectively represents the Company’s deferred credits and have been excluded from the fair value calculation. See Note 4 for additional information.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Certain assets and liabilities are reported at fair value on a recurring basis (unless otherwise noted below) in Callon’s Consolidated Balance Sheet. The following methods and assumptions were used to estimate the fair values:
Commodity Derivative Instruments. The fair value of commodity derivative instruments is derived using a valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract, and the values are corroborated by quotes obtained from counterparties to the agreements. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair-value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. See Note 5 for additional information regarding the Company’s derivative instruments.
The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis for each hierarchy level:
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
The derivative fair values above are based on analysis of each contract. Derivative assets and liabilities with the same counterparty are presented here on a gross basis, even where the legal right of offset exists. See Note 5 for a discussion of net amounts recorded in the Consolidated Balance Sheet at December 31, 2013.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities are reported at fair value on a nonrecurring basis in Callon’s Consolidated Balance Sheet. The following methods and assumptions were used to estimate the fair values:
Other Property and Equipment. As discussed in Note 13, the Company’s decision to abandon certain of its other property and equipment, that had been classified as held for sale, resulted in an impairment charge of $1,707 which is included in the Company’s Statement of Operations for the year ended December 31, 2013. The impairment charge was valued using level 3 inputs.
Acquisition. During the second quarter of 2013, the Company acquired approximately 2,468 gross (2,186 net) acres in Reagan and Upton Counties, Texas, which is located in the southern portion of the Midland Basin for a purchase price of $11,000. The acquisition also included seven gross vertical wells and 1,301 barrels of oil equivalent proved reserves. The Company valued the acquired assets in accordance with the method described below. In accordance with the acquisition method of accounting, the purchase price of the Company’s acquisition during the period has been allocated to the assets acquired and liabilities assumed based on their estimated fair values on the acquisition date. In valuing the acquired assets and liabilities assumed, fair values were based on expected future cash flows based on estimated reserve quantities; costs to produce and develop reserves; and oil and gas forward prices. The purchase price of the Company’s acquisition during the period was $11,000 with approximately $2,000 allocated to unevaluated oil and gas properties and approximately $9,000 allocated to evaluated oil and gas properties. Asset retirement obligations assumed in connection with the transaction were insignificant due to the nature of the properties acquired. The unaudited pro forma results of the properties acquired are immaterial to the Company’s financial statements. The fair value measurements were based on significant inputs not observable in the market and thus represent a level 3 measurement.
NOTE 7 - Employee Benefit Plans
The Company utilizes various forms of incentive compensation designed to align the interest of the executives and employees with those of its stockholders. Tabular disclosures related to the share-based awards are presented in Note 8. The narrative that follows provides a brief description of each plan, summarizes the overall status of each plan and discusses current year awards under each plan:
Savings and Protection Plan
The Savings and Protection Plan (“401-K Plan”) provides employees with the option to defer receipt of a portion of their compensation, and the Company may, at its discretion, match a portion of the employee’s deferral with cash. The Company may also elect, at its discretion, to contribute a non-matching amount in cash and Company Common Stock to employees. The amounts held under the 401-K Plan are invested in various funds maintained by a third party in accordance with the directions of each employee. An employee is fully vested, including Company discretionary contributions, immediately upon participation in the 401-K Plan. The total amounts contributed by the Company, including the value of the common stock contributed, were $923, $918 and $811 in the years 2013, 2012 and 2011, respectively.
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
2011 Omnibus Incentive Plan (the “2011 Plan”)
The 2011 Plan, which became effective May 12, 2011 following shareholder approval, authorized and reserved for issuance 2,300 shares of common stock, which may be issued upon exercise of vested stock options and/or the vesting of any other share-based equity award that is granted under this plan. The 2011 Plan is the Company’s only active plan, and included a provision at inception whereby all remaining, un-issued and authorized shares from the Company’s previous share-based incentive plans became issuable under the 2011 Plan. This transfer provision resulted in the transfer of an additional 841 shares into the plan, increasing the quantity authorized and reserved for issuance under the Plan to 3,141 at the inception of the plan. Another provision provided that shares which would otherwise become available for issue under the previous plans as a result of vesting and/or forfeiture of any equity awards existing as of May 12, 2012, would also increase the authorized shares available to the 2011 Plan. As of December 31, 2013, the 2011 Plan had 1,192 shares remaining and eligible for future issuance.
Equity awards issued under this plan may be subject to various vesting, accelerated vesting, and forfeiture provisions upon the occurrence of certain events. Any vested but unexercised options contractually expire 10 years from the date of grant. Equity awards under the 2011 Plan generally vest over time but may also be subject to attaining a specified performance metrics and may be immediate or cliff vest at a specified date. The Company will recognize expense on the grant date for all immediately vesting awards, while it will recognize expense ratably over the requisite service (i.e. vesting) period for both cliff and ratably vesting awards. For performance-based awards, the Company recognizes expense based on its analysis of the performance criteria, and records or reverses expense as necessary based on its analysis. For market-based awards, the Company recognizes expense based on its analysis of the market criteria, and records expense as necessary based on its analysis. Awards with a market-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and no shares ultimately vest or are awarded.
Cash-Settleable RSU Awards
Certain of the Company’s RSUs awarded require cash-settlement. Cash-settleable RSU awards are accounted for as liabilities as the Company is contractually obligated to settle these awards in cash, and are recorded in the Company’s consolidated balance sheet for the ratable portion of their fair values. The fair value of the Company’s market-based RSU is calculated using a Monte Carlo valuation model, which considers such inputs as the Company’s and its peer group’s stock prices, a risk-free interest rate, and an estimated volatility for the Company and its peer group. Changes in the fair value of cash-settleable awards are recorded as adjustments to compensation expense.
Market-based RSUs: A significant portion of the Company’s cash-settleable RSU awards include a market-based vesting condition and may ultimately vest at a quantity different than the base RSUs awarded. The number of RSUs that cliff-vest is based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between 0% and 200% of the base units awarded.
As of December 31, 2013, the Company had the following cash-settleable RSU awards outstanding (including those that are not based on a market condition):
For the year ended December 31, 2013, 260 market-based cash-settleable RSUs subject to the peer market-based vesting described above vested at 100% of their issued units, resulting in a cash payment of $1,669. Also during 2013, 65 non-market-based cash settleable RSUs vested, resulting in a cash payment of $239. During 2012, 364 market-based cash-settleable RSUs vested at 150%, resulting in a cash payment of $2,626. Also during 2012, 143 non-market-based cash settleable RSUs vested, resulting in a cash payment of $763. See Note 8 for additional information regarding cash-settleable RSUs.
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
NOTE 8 - Share-Based Compensation
As discussed in Note 7, the Company grants various forms of share-based compensation awards to employees of the Company and its subsidiaries and to non-employee members of the Board of Directors. At December 31, 2013, shares available for future share-based awards, including stock options or restricted stock grants, under the Company’s only active plan, the 2011 Plan, were 1,192.
The following table presents share-based compensation expense for each respective period:
(a)
The portion of this share-based compensation expense that was included in general and administrative expense totaled $5,751, $4,081 and $2,502 for the same years respectively, and the portion capitalized to oil and gas properties was $3,791, $3,263 and $1,891, respectively.
The following table presents the specified share-based compensation expense for the indicated periods:
The Company’s future expected share-based compensation cost related to unvested RSU and cash-settleable RSU awards is expected to be recognized over a weighted-average period of 1.4 years.
The following table summarizes the Company’s cash-settleable RSU awards for the periods indicated:
Stock Options
The Company issued no stock options for the past three years and had no options vest or forfeit during 2013. Additionally, no options were exercised, 15 options expired unexercised during the year. As of December 31, 2013, the Company had 52 options outstanding and exercisable at a weighted average exercise price per option of $13.75, with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 2.3 years.
As of December 31, 2012, the Company had 67 options outstanding and exercisable at a weighted average exercise price per option of $11.82, with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 2.7 years. The Company net-share settles option exercises and therefore receives no cash proceeds from the exercise of stock options.
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
Restricted Stock Units
The following table represents unvested restricted stock activity for the year ended December 31, 2013:
a.
The fair value of shares vested was $2,689.
NOTE 9 - Equity Transactions
On May 30, 2013, the Company issued 78,947 of 10.0% Series A Cumulative Preferred Stock (the “Preferred Stock”) and received $70,035 net proceeds after deducting the underwriting commissions and offering expenses. The sale consisted of 1,579 shares of Preferred Stock, par value $0.01 per share, public offering price of $47.50 per share and liquidation preference of $50.00 per share in an underwritten public offering. The Preferred Stock ranks senior to the Company’s common stock with respect to the payment of dividends and distribution of assets upon liquidation or dissolution. The Preferred Stock has no stated maturity and is not subject to mandatory redemption or any sinking fund. The Preferred Stock will remain outstanding indefinitely unless repurchased by the Company or converted into Callon common stock in connection with certain changes in control as defined in the Preferred Stock prospectus.
Holders of the Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors (the “Board”), 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. The first dividend date for the Preferred Stock was June 30, 2013, and these dividends were paid on June 28, 2013 (as June 30 fell on a weekend) in the amount of $0.43 per share or $679 for the stub period beginning with the issuance on May 30, 2013 through the dividend date on June 30, 2013. For the subsequent quarters ended September 30 and December 31, 2013, the Board of Directors declared for each quarter a dividend of $1.25 per share, or a total of $1,974, on the Company’s Preferred Stock, resulting in total dividend expense recognized in 2013 of $4,627.
Beginning on May 30, 2018, the Company may, solely at its option, redeem the Preferred Stock in whole at any time, or in part from time to time, for cash at a redemption price of $50.00 per share, plus accrued and unpaid dividends (whether or not declared) to the redemption date. The Company may redeem the Preferred Stock following certain changes of control as defined in the Preferred Stock prospectus, in whole or in part, within 120 days after the date on which the change of control has occurred, for cash at $50.00 per share, plus accrued and unpaid dividends (whether or not declared) to the redemption date. If the Company elects not to exercise this option, the holders of the Preferred Stock have the option to convert each share of Preferred Stock into a predefined number of Company common shares, subject to certain adjustments.
As defined in a provision of the Preferred Stock prospectus, the common shares reserved for issuance vary based on the number of authorized common shares. Based on the Company’s 60,000 authorized shares at December 31, 2013, 16,800 shares were reserved for a potential conversion. Subsequent to December 31, 2013, via a majority shareholder vote, the number of authorized shares of common stock was increased from 60,000 to 110,000 with a corresponding increase in the number of common shares reserved for a potential conversion to a maximum of 42,200 shares. Based on the Company’s closing common stock price of $6.53 per share on December 31, 2013, the Company reserved 12,090 shares to satisfy the potential conversion.
Except as required by law, holders of the Preferred Stock will have no voting rights unless dividends fall into arrears for six or more quarterly periods (whether or not consecutive). In that event and until such dividends in arrears are paid in full, the holders will be entitled to elect two directors to the Board, which will increase in size by that same number of directors.
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
During February, 2011, the Company received $73,765 in net proceeds from the public offering of 10.1 million shares of its common stock, which included the issuance of 1.1 million shares pursuant to the underwriters’ over-allotment option. The Company used $35,062 of the proceeds to repurchase $31,000 principal amount of its Senior Notes, with the remaining proceeds intended for general corporate purposes including the planned development of the Company’s Permian basin and other onshore assets.
NOTE 10 - Income Taxes
The following table presents Callon’s net tax benefits relating to its reported net losses and other temporary differences from operations:
Prior to 2012, the Company carried a full valuation allowance against its net deferred tax assets. The Company considered both the positive and negative evidence in determining whether it was more likely than not that its deferred tax assets were recoverable. The Company incurred a loss in 2008, primarily as a result of a write-down of its oil and natural gas properties following the ceiling test, which created a loss on an aggregate basis for the three-year period ended December 31, 2008. Primarily as a result of recent cumulative losses, the Company established a full valuation allowance as of December 31, 2008, and continued to carry the full valuation allowance each reporting period until December 31, 2011. At December 31, 2011, after considering all available positive and negative evidence, including the Company’s profitable operations from 2009 to 2011 which resulted in income on an aggregate basis for the three year period ended December 31, 2011, and future operating results based on proved reserves, the Company determined that it was more likely than not that it would fully utilize its deferred tax assets recorded at December 31, 2011. Therefore, the Company reversed its valuation allowance at December 31, 2011.
If not utilized, the Company’s federal operating loss (“NOL”) carryforwards will expire as follows:
The Company has limited state taxable income. Accordingly, the Company has established a full valuation allowance on the tax benefits associated with the state net operating loss carryforwards of approximately$167,795 which expire in years through 2033, as the Company does not anticipate generating taxable state income in the states in which these carryforwards apply. These amounts are not included in the deferred tax summary table above.
In 2009, the Company began to shift its operational focus from exploration, development and production in the Gulf of Mexico to the acquisition and development of onshore properties. This shift in exploration and development activity resulted in an increase in Texas income from production. This, coupled with the Company’s exit from the Gulf of Mexico (the sale of its interest in the Habanero field in December 2012 and the Medusa field in December 2013), results in a change in the projected future Texas state tax rate beyond 2013 as a component of overall anticipated future taxes.
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
The Company had no significant unrecognized tax benefits at December 31, 2013. Accordingly, the Company does not have any interest or penalties related to uncertain tax positions. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense. Tax periods for years 2001 through 2013 remain open to examination by the federal and state taxing jurisdictions to which the Company is subject.
Below is a reconciliation of the reported amount of income tax expense attributable to continuing operations to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations.
NOTE 11 - Asset Retirement Obligations
The following table summarizes the activity for the Company’s asset retirement obligations:
Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the Consolidated Balance Sheets at December 31, 2013 as long-term restricted investments were $3,806. These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties.
On December 5, 2013, the Company closed on its agreement to sell its interest in the Medusa field, Medusa Spar LLC, and substantially all of its Gulf of Mexico shelf properties to W&T Offshore, Inc. (“W&T”). Under the agreement, W&T will assume an estimated $4,765 of the ARO related to these offshore assets.
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
The Company’s total revisions to estimates of $3,811 for the year ended December 31, 2013 relate to downward revisions related to the changes in the expecting timing of the abandonment.
NOTE 12 - Supplemental Information on Oil and Natural Gas Operations (Unaudited)
Oil and Natural Gas Properties
The following table discloses certain financial data relating to the Company’s oil and natural gas activities, all of which are located in the United States.
Unevaluated property costs primarily include lease acquisition costs incurred at federal lease sales, unevaluated drilling costs, seismic, capitalized interest and certain overhead costs related to exploration and development. These costs are directly related to the acquisition and evaluation of unproved properties and major development projects. The excluded costs and related reserves are included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. The Company expects that the majority of these costs will be evaluated over the next three but within five years. The Company’s unevaluated property balance decreased by $25,554 to $43,222 at December 31, 2013 compared to December 31, 2012. A significant portion of this decrease relates to the transfer of drilling and completion costs from the unevaluated property base to the evaluated property base.
Subsequent to December 31, 2013 and through March 10, 2014, the Company completed six horizontal exploration wells, drilled four horizontal wells and had two in progress. Additionally, the Company drilled two vertical exploratory wells and will be evaluating the results.
Depletion per unit-of-production (BOE) amounted to $31.12, $31.56 and $26.42 for the years ended December 31, 2013, 2012, and 2011, respectively. Lease operating expense per unit-of-production (BOE) amounted to $14.00, $14.81, and $9.92 for the years ended December 31, 2013, 2012, and 2011, respectively.
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
Under the full-cost accounting rules of the SEC, 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 generally 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 “ceiling” is exceeded. Given the volatility of oil and natural gas prices, it is reasonably possible that the Company’s estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. If oil and natural gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and natural gas properties could occur in the future. For the years ended December 31, 2013, 2012, and 2011, the Company recorded no impairment charges related to its oil and natural gas properties as a result of this calculation.
Estimated Reserves
The Company’s proved oil and natural gas reserves at December 31, 2013, 2012 and 2011 have been estimated by Huddleston & Co., Inc., the Company’s independent petroleum engineers. The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions.
There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only, and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves.
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
Changes in the estimated net quantities of oil and natural gas reserves, all of which are located onshore within the continental United States and offshore within the Gulf of Mexico, are as follows:
Total Proved Reserves: The Company ended 2013 with estimated net proved reserves of 14,857 MBOE, representing a 6% increase over 2012 year-end estimated net proved reserves of 14,072 MBOE. The increase is primarily due the Company’s development of its Permian basin, on which it drilled a total of 26 oil wells during 2013. The increase is offset by the sale of the Company’s interest in the Medusa field and due to the Company’s reclassification of certain vertical PUD locations to the horizontal probable and PUD categories.
Extrapolation of performance history and material balance estimates were utilized by the Company’s independent petroleum and geological firm to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to nonproducing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production, and to a small extent, horizontal PDP and PUD categories.
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
Proved Undeveloped Reserves: The Company annually reviews its proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists. Generally, reserves for the Company’s onshore properties are booked as PUDs only if the Company has plans to convert the PUDs into proved developed reserves within five years of the date they are first booked as PUDs. The Company’s PUDs increased 1% to 7,387 MBOE from 7,337 MBOE at December 31, 2013 and 2012, respectively. The Company added 5,168 MBOE to its PUDs, primarily from the continued horizontal development of its Permian Basin properties. The increase in Permian Basin PUDs was partially offset by the reclassification of 3,724 MBOE, or 51%, included in the year-end 2012 PUD reserves related to vertical PUD locations that were reclassified to the horizontal probable, and to a small extent, horizontal PDP and PUD categories. The reclassified vertical PUDs include Wolfberry PUD locations that included certain target zones that are now expected to be more efficiently developed by the Company’s multi-level horizontal drilling programs initiated in 2012. Also offsetting the Permian Basin PUD growth were the sale of 1,297 MBOE, or 18%, included in the year-end 2012 PUD reserves related to our Medusa field and the conversion of a small portion of 2012 PUD reserves to PDPs during 2013 from the drilling of vertical wells.
The Company’s PUDs decreased 18% to 7,337 MBOE from 8,925 MBOE at December 31, 2012 and 2011, respectively. Additions during the year added 2,344 MBOE to the Company’s PUDs, offset by (1) 557 MBOE primarily comprised of transfers to PDPs as a result of our development program, (2) 1,148 MBOE related to the sale of Habanero, and (3) 2,227 MBOE related to reductions in our PUD reserves, primarily related to the Haynesville Shale, by amounts no longer deemed to be economic PUDs at year-end. Of the Company’s year-end 2011 PUD reserves, 6% were converted to proved developed producing reserves by year end 2012, at a total cost of approximately $19 million, net.
Of the Company’s 2012 PUDs, 1,297 MBOE were attributable to the Company’s offshore properties in the Medusa field in the Gulf of Mexico. As previously noted, the Company sold its interest in the Medusa field during 2013.
Standardized Measure
The following tables present the standardized measure of 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 at December 31, 2013. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. 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. The following table summarizes the average 12-month oil and natural gas prices net of differentials for the respective periods:
Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate.
Natural gas production from our deepwater and Permian Basin properties has a high Btu content of separator natural gas. The natural gas Mcf prices of $5.45 and $4.81 used in the 2013 and 2012 reserve estimates include adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties. The oil prices of $92.16 and $94.68 used in the 2013 and 2012 reserve estimates have been adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality.
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
NOTE 13 - Other
Commitments and Contingencies: The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company.
The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment are not expected to have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies hereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities.
Global Settlement with Joint Interest Partner: During 2011, the Company and a joint interest partner entered into a settlement agreement related to various disputes. All matters were settled and as result of the settlement agreement the Company received an interest in other specialized deep water property and equipment. The Company recognized a gain of $5,041 as a result of the settlement and classified the property and equipment received as held for sale assets, included within other property and equipment since the Company had no use for this type of equipment in its operations. Since the settlement with its joint interest partner, the Company has sold a portion of these assets and has continued to actively market the remaining assets throughout 2012 and 2013. During 2012, after selling assets valued at $527 during the year, the Company determined that certain equipment components were not usable without additional rework and thus recorded an impairment charge to its Statement of Operations of $1,177 during
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
2012. During 2013, after selling assets value at $114 during the year, the Company has made a decision to abandon the equipment. As such the Company recorded an impairment charge of $1,707 to its Statement of Operations, representing the remaining value of this equipment.
Operating Leases: In April 2012, the Company took delivery of a drilling rig (the “Cactus 1 Rig”) for a term of two years, which it subsequently renewed on March 6, 2014 for an additional two year term ending April 2016. On August 1, 2013, the Company contracted a second horizontal drilling rig (the “Patterson Rig”) for a one-year term, though the Company provided notice on February 17, 2014 that it will cancel its Patterson rig contract on or about March 17, 2014. Under the early termination provisions of the agreement, estimated termination payments for this rig will be approximately $2,055 in 2014. Should the lessor be able to re-charter the rig, the termination payments would be reduced. To replace the Patterson Rig, the Company contracted a replacement rig (the “Cactus 2 Rig”) for a term of two years, which is scheduled to commence operations on April 1, 2014. Similar to the Patterson Rig, the Cactus 1 and 2 Rig lease agreements also include early termination provisions that would reduce the minimum rentals under the agreement, assuming the lessor is unable to re-charter the rig and staffing personnel to another lessee. Lease costs recorded during 2013 were $12,860. Lease payments as of December 31, 2013 will approximate $13,954, $9,308 and $2,295 in 2014, 2015 and 2016, respectively. Including the additional lease commitments executed subsequent to December 31, 2013, the Company’s drilling rig lease commitments as of March 10, 2014 are $19,732, $18,250 and $4,500 in 2014, 2015, and 2016, respectively.
Property Acquisitions and Dispositions
Acquisitions
During the second quarter of 2013, the Company acquired approximately 2,468 gross (2,186 net) acres in Reagan and Upton Counties, Texas, which is located in the southern portion of the Midland Basin and which is prospective for both horizontal and vertical drilling. The acquisition also included seven gross vertical wells and 1,301 barrels of oil equivalent proved reserves. The purchase price of $11,000 was funded using a portion of the proceeds from the preferred stock offering (discussed in Note 9).
During the first quarter of 2012, the Company acquired approximately 16,233 gross (14,653 net) acres in Borden County, which is located in the northern Midland basin. The northern Midland basin has had limited drilling activity compared with the southern Midland basin (where our current production is located), increasing the economic risk related to these drilling activities. The purchase price of $14,538 was funded from existing cash balances. During the third quarter of 2012, we acquired an additional 8,095 gross acres (6.964 net) in this area for a total consideration of $4,835.
During the second quarter of 2012, the Company signed a purchase and sale agreement to acquire 2,319 gross (1.762 net) acres in southern Reagan County, Texas for a total purchase price of $12,012, which was financed with a draw on the Credit Facility. The transaction had an effective date of May 1, 2012 and closed on July 5, 2012.
Dispositions
During the fourth quarter of 2013, the Company closed on the sale of its 15.0% working interest in the Medusa field (Mississippi Canyon blocks 582 and 538), our 10.0% membership interest in Medusa Spar LLC, and substantially all of our remaining Gulf of Mexico shelf properties. The Company sold its interest in Medusa to W&T, an unrelated third-party, for a total net cash consideration of approximately $88,000 after customary purchase price adjustments. Also during the fourth quarter of 2013, the Company closed on the sale of its 69% interest in the Swan Lake field for $2,000. This was the Company’s only field in the Haynesville shale. Consistent with the Company’s accounting policy discussed in Note 2, the proceeds from these sales were accounted for as a reduction to capitalized costs as the sale did not significantly alter the relationship between capitalized costs and proved reserves.
Effective December 28, 2012, the Company closed on the sale of its 11.25% working interest in the Habanero field (Garden Banks Block 341). The Company sold its interest in Habanero to Shell Offshore Inc., a subsidiary of Royal Dutch Shell Plc, for an estimated net cash consideration of $39,410 after customary purchase price adjustments. As noted above, the proceeds from this sale were accounted for as a reduction to capitalized costs as the sale did not significantly alter the relationship between capitalized costs and proved reserves.
Callon Petroleum Company
Notes to the Consolidated Financial Statements
(All amounts in thousands, except well, acreage, per-share and per-derivative instrument data)
NOTE 14 - Summarized Quarterly Financial Information (Unaudited)
ITEM 9.
ITEM 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
There have been no disagreements with the independent auditors on any matters of accounting principles or practices, financial statement disclosure, or auditing scope or procedures.
ITEM 9A.
ITEM 9A. Controls and Procedures
Disclosure Controls and Procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. The Company’s principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) were effective as of December 31, 2013.
Management’s Report on Internal Control over Financial Reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. generally accepted accounting principles. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2013 based on the framework in Internal Control - Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission (1992 framework)(the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2013.
Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Company’s independent registered public accounting firm has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of December 31, 2013, which follows Part II, Item 9B
ITEM 9B. Other Information
Submissions of Matters to a Vote of the Security Holders
None.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of
Callon Petroleum Company
We have audited Callon Petroleum Company’s internal control over financial reporting as of December 31, 2013 based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework)(the COSO criteria). Callon Petroleum Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Callon Petroleum Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the COSO criteria.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Callon Petroleum Company as of December 31, 2013 and 2012, and the related statements of operations, comprehensive income, cash flow, and changes in stockholders’ equity (deficit) for each of the three years in the period ended December 31, 2013, and our report dated March 12, 2014 expressed an unqualified opinion thereon.
/s/Ernst & Young LLP
New Orleans, Louisiana
March 12, 2014
PART III.
ITEM 10.
ITEM 10. Directors, Executive Officers and Corporate Governance
For information concerning Item 10, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 15, 2014 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
The Company has adopted a code of ethics that applies to the Company’s chief executive officer, chief financial officer and chief accounting officer. The full text of such code of ethics has been posted on the Company’s website at www.callon.com, and is available free of charge in print to any shareholder who requests it. Request for copies should be addressed to the Secretary at mailing address Post Office Box 1287, Natchez, Mississippi 39121.
ITEM 11.
ITEM 11. Executive Compensation
For information concerning Item 11, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 15, 2014 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
ITEM 12.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
For information concerning the security ownership of certain beneficial owners and management, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 15, 2014 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
ITEM 13.
ITEM 13. Certain Relationships and Related Transactions and Director Independence
For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 15, 2014 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
ITEM 14.
ITEM 14. Principal Accountant Fees and Services
For information concerning Item 14, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 15, 2014 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
PART IV.
ITEM 15.
ITEM 15. Exhibits
SIGNATURES