ITEM 1A. RISK FACTORS
The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, financial condition or results of operation.
Oil and gas price volatility, including the recent decline in oil and gas prices, could adversely affect our financial condition, financial results, cash flows, access to capital and ability to grow.
Our future financial condition, revenues, results of operations, rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prices we receive for our oil and gas production. Oil and natural gas prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical conditions. This price volatility also affects the cash flow we will have available for capital expenditures as well as our ability to borrow money or raise additional capital. The prices for oil and gas are subject to a variety of factors that are beyond our control. These factors include, but are not limited to, the following:
•
the level of consumer demand for oil and natural gas;
•
the domestic and foreign supply of oil and natural gas;
•
oil and natural gas processing, gathering and transportation availability, and the availability of refining capacity;
•
the price and level of foreign imports of oil and natural gas;
•
the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
•
domestic and foreign governmental regulations and taxes;
•
the supply of CO2;
•
the supply of other inputs necessary to our production;
•
the price and availability of alternative fuel sources;
•
weather conditions;
•
financial and commercial market uncertainty;
•
political conditions or hostilities in oil and natural gas producing regions, including the Middle East and South America; and
•
worldwide economic conditions.
These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and gas price movements with any certainty. For example, during the five years prior to December 31, 2014, the posted price for West Texas Intermediate light sweet crude oil, commonly referred to as West Texas Intermediate or WTI, has ranged from a low of $53.45 per barrel, or Bbl, in December 2014 to a high of $113.39 per Bbl in April 2011. The Henry Hub spot market price of natural gas has ranged from a low of $1.82 per million British thermal units, or MMBtu, in April 2012 to a high of $8.15 per MMBtu in February 2014. Over the past several months, oil prices have declined from over $105.00 per Bbl in June 2014 to below $45.00 per Bbl in January 2015 due in large part to increasing supplies and weakening demand growth, and have remained low compared to prices in the first half of 2014.
Lower oil and natural gas prices for an extended period would not only reduce our revenue, but could reduce the amount of oil and natural gas we can produce economically, and as a result, could have a material adverse effect on our financial condition, results of operations, and reserves. We could also determine during periods of low commodity prices to shut in or curtail production from our wells and to defer drilling new wells challenging our ability to produce at commercially paying quantities required to hold our leases.
If commodity prices remain at current levels for an extended period, we may, among other things, be unable to meet our financial obligations, including payments on our senior secured revolving credit facility and our senior notes, or be unable to make planned capital expenditures.
We expect to write down the carrying values of our properties in 2015 if oil and natural gas prices remain low, and further price declines could result in additional write-downs in the future, which could negatively impact our results of operations.
We utilize the full cost method of accounting for costs related to our oil and natural gas properties. Under this method, all costs incurred for both productive and nonproductive properties are capitalized and amortized on an aggregate basis using the units-of-production method. However, these capitalized costs are subject to a ceiling test which limits such pooled costs to the aggregate of the present value of estimated future net revenues attributable to proved oil and gas reserves discounted at 10%,
adjusted for derivatives accounted for as cash flow hedges and net of tax considerations, plus the cost of unproved properties not being amortized. The full cost ceiling is evaluated at the end of each quarter using the SEC prices for oil and natural gas in effect at that date as adjusted for our derivative positions deemed “cash flow hedge positions.” A write-down of oil and natural gas properties does not impact cash flow from operating activities, but does reduce net income. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date.
Oil and natural gas prices are volatile and this and other factors, without mitigating circumstances, could require us to further write down capitalized costs and incur corresponding non-cash charges to earnings. Any such further write-downs could have a material adverse effect on our financial condition and results of operations. We did not have a ceiling test write-down in 2012, 2013 or 2014. Due to the substantial decline of commodity prices during the third and fourth quarters of 2014, which have remained low during the first quarter of 2015, we anticipate that we will have a ceiling test write-down during 2015. It is difficult to predict with reasonable certainty the amount of expected future impairments given the many factors impacting the ceiling test calculation including, but not limited to, future pricing, operating costs, upward or downward reserve revisions, reserve adds, and tax attributes.
The actual quantities and present value of our proved reserves may be lower than we have estimated.
Estimating quantities of proved oil and natural gas reserves is a complex process. It requires interpretations of available technical data and various estimates and assumptions, including estimates based upon assumptions relating to economic factors such as oil and natural gas prices, production costs, severance and excise taxes, capital expenditures, workovers, remedial costs, and the assumed effect of governmental regulation. There are numerous uncertainties about when a property may have proved reserves as compared to possible or probable reserves, including with respect to our EOR operations. Reserve estimates are, therefore, inherently imprecise and, although we are reasonably certain of recovering the quantities we disclose as proved reserves, actual results will vary from our estimates. Any significant variations in the interpretations or assumptions underlying our estimates or changes of conditions (e.g. economic growth and/or regulation) could cause the estimated quantities and net present value of our reserves to differ materially. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and developmental drilling, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production by operators on adjacent properties.
You should not assume that the present values referred to in this report represent the current market value of our estimated oil and natural gas reserves. The timing of production and expenses associated with the development and production of oil and natural gas properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. In accordance with requirements of the SEC, the estimates of present values are based on a twelve-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the twelve-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of these estimates. In addition, the effects of derivative instruments are not reflected in these assumed prices. Our December 31, 2014 reserve report used prices of $4.35 per Mcf for natural gas, $94.99 per Bbl for oil and $36.10 per Bbl for natural gas liquids. These prices are substantially higher than the current and expected 2015 prices for oil and natural gas.
A significant portion of total proved reserves as of December 31, 2014 are undeveloped, and those reserves may not ultimately be developed.
As of December 31, 2014, approximately 42% of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflect our plans to make significant capital expenditures to convert our proved undeveloped reserves into proved developed reserves including approximately $0.8 billion during the five years ending in 2019. You should be aware that actual development costs may exceed estimates, development may not occur as scheduled and results may not be as estimated. If we choose not to develop our proved undeveloped reserves, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, proved undeveloped reserves generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking. We may be required to write off any reserves that are not developed within this five-year time frame unless such reported reserves are otherwise exempted from the SEC’s five-year reporting rules.
Some of our reserves are subject to EOR methods and the failure of these methods may have a material adverse effect on our financial condition, results of operations and reserves.
Of our 57.5 million MMBoe of reserves on our active EOR properties as of December 31, 2014, 43.1 MMBoe were based on EOR methods including the injection of CO2 and represent approximately 27% of our total proved reserves. Some of these properties have not been injected with CO2 and recovery factors cannot be estimated with precision. Accordingly, such projects may not result in significant proved reserves or improvements in anticipated production levels.
We do not currently have a supply of CO2 for all of our unproved properties with CO2 EOR potential, and we cannot assure you that we will be able to obtain such a supply on commercially reasonable terms. In addition, many of our planned EOR projects
will require significant investments in pipeline, compression facilities, and other infrastructure, and we may need to raise additional capital to fund these projects. We cannot assure you that such funding will be available on commercially reasonable terms. The availability of CO2 supply and financing of CO2 projects could affect the timing of our planned EOR programs and impact our ability to implement such plans.
Our ability to develop our EOR reserves will depend on whether we can successfully implement our planned EOR programs, and our failure to do so could have a material adverse effect on our financial condition, results of operations and reserves.
Limitations or restrictions on our ability to obtain water may have an adverse effect on our operating results.
Our operations require significant amounts of water for drilling and hydraulic fracturing. Limitations or restrictions on our ability to obtain water from local sources may require us to find remote sources. In addition, treatment and disposal or such water after use is becoming more highly regulated and restricted. Thus, costs for obtaining and disposing of water could increase significantly, potentially limiting our ability to engage in hydraulic fracturing. This could have a material adverse effect on our operations.
The development of the proved undeveloped reserves in our active EOR projects may take longer and may require higher levels of capital expenditures than we currently anticipate.
As of December 31, 2014, undeveloped reserves comprised 47% of the total estimated proved reserves of our active EOR projects. As of December 31, 2014, we expect to incur future development costs of $1.0 billion, including $306.0 million for CO2 purchase, compression and transportation, over the next 30 years to substantially develop these reserves. The future development costs for our active EOR projects are 60% of our total estimated future development and abandonment costs of $1.7 billion as of December 31, 2014. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. In addition, the development of these reserves will require the use of EOR techniques, including water flood and CO2 injection installations, the success of which is still subject to interpretation and predictability by reservoir engineers. Therefore, ultimate recoveries from these fields may not match current expectations.
Competition in the oil and gas industry is intense and many of our competitors have greater financial and other resources than we do.
We operate in the highly competitive areas of oil and natural gas production, acquisition, development, and exploration and face intense competition from both major and other independent oil and gas companies:
•
seeking to acquire desirable producing properties or new leases for future development or exploration; and
•
seeking to acquire the equipment and expertise necessary to operate and develop our properties.
Many of our competitors have financial and other resources substantially greater than ours, and some of them are fully integrated oil companies. These companies may be able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to develop our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, select suitable prospects and consummate transactions in this highly competitive environment.
Significant capital expenditures are required to replace our reserves.
Our development, exploration, and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations, debt financing, private issuances of common stock and proceeds from asset sales. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of oil and natural gas, and our success in developing and producing new reserves. If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may not be able to access additional bank debt or other methods of financing on commercially reasonable terms to meet these requirements. If revenue were to decrease as a result of lower oil and natural gas prices or decreased production, and our access to capital were limited, we would have a reduced ability to replace our reserves which may have an adverse effect on our results of operations and financial condition.
If we are not able to replace reserves, we may not be able to sustain production.
Our future success depends largely upon our ability to find, develop, or acquire additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves and production will decline over time. In addition, approximately 42% of our total estimated proved reserves (by volume) at December 31, 2014 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling and EOR operations. Our December 31, 2014 reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 21%, 14%, and 12% for the next three years. Thus, our future oil and natural gas reserves and production and, therefore, our financial condition, results of operations, and cash flows are highly
dependent on our success in efficiently developing our current reserves and economically discovering or acquiring additional recoverable reserves. Due to lower oil prices, we are significantly reducing capital expenditures in 2015 which will result in lower than average replacement of reserves when compared to previous years.
Development and exploration drilling may not result in commercially productive reserves.
Drilling activities are subject to many risks, including the risk that commercially productive reservoirs will not be encountered. We cannot assure you that new wells we drill will be productive or that we will recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or may be economically recovered and/or produced. Drilling for oil and natural gas often involves 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 at then-realized prices after deducting drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. These risks are magnified when operating in an environment of low crude oil prices like we are currently experiencing in the the United States. Further, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including:
•
unexpected drilling conditions;
•
title problems;
•
pressure or lost circulation in formations;
•
equipment failures or accidents;
•
adverse weather conditions;
•
decline in commodity prices;
•
compliance with environmental and other governmental requirements; and
•
increases in the cost of, or shortages or delays in the availability of, drilling rigs, equipment and services.
If, for any reason, we are unable to economically recover reserves through our exploration and drilling activities, our results of operations, cash flows, growth, and reserve replenishment may be materially affected.
A significant portion of our operations are located in Oklahoma and the Texas Panhandle, making us vulnerable to risks associated with operating in a limited number of major geographic areas.
As of December 31, 2014, almost 100% of our proved reserves and production was located in the Mid-Continent geographic area. This concentration could disproportionately expose us to operational and regulatory risk in this area. This lack of diversification in location of our key operations could expose us to adverse developments in our operating areas or the oil and natural gas markets, including, for example, transportation or treatment capacity constraints, curtailment of production or treatment plant closures for scheduled maintenance. These factors could have a significantly greater impact on our financial condition, results of operations and cash flows than if our properties were more geographically diversified.
We are subject to complex laws and regulations, including environmental and safety regulations, which can adversely affect the cost, manner, and feasibility of doing business.
Our operations and facilities are subject to certain federal, state, and local laws and regulations relating to the exploration for, and development, production, and transportation of, oil and gas, as well as environmental and safety matters. Although we believe that we are in substantial compliance with all applicable laws and regulations, and are currently evaluating the extent of applicability and preparing to comply to the extent applicable with proposed and newly adopted greenhouse gas reporting and permitting requirements, we cannot be certain that existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not harm our business, results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with environmental and other governmental regulations such as:
•
land use restrictions;
•
drilling bonds and other financial responsibility requirements;
•
spacing of wells;
•
reporting on emissions of greenhouse gases;
•
permitting of emissions of greenhouse gases and other regulated air pollutants;
•
unitization and pooling of properties;
•
habitat and endangered species protection, reclamation and remediation, and other environmental protection;
•
well stimulation processes;
•
produced water disposal;
•
CO2 pipeline requirements;
•
safety precautions;
•
operational reporting; and
•
taxation.
Under these laws and regulations, we could be liable for:
•
personal injuries;
•
property and natural resource damages;
•
oil spills and releases or discharges of hazardous materials;
•
well reclamation costs;
•
remediation and clean-up costs and other governmental sanctions, such as fines and penalties;
•
other environmental damages; and
•
additional reporting, permitting or other issues arising from emissions of greenhouse gases and other regulated air pollutants;
•
and fines, penalties, and / or consent orders for non-compliance with the Clean Air Act.
Our operations could be significantly delayed or curtailed and our costs of operations could significantly increase as a result of regulatory requirements or restrictions. Additionally, regulations promulgated pursuant to the Clean Air Act or other mandatory federal legislation requiring monitoring and reporting of air pollutant emissions continue to evolve and may impose new restrictions on these emissions resulting in liability for exceeding permitted air pollutant emission rates or other mandatory caps on greenhouse gas emissions. While we are preparing for compliance with newly adopted requirements, at this time we are unable to predict the ultimate cost of compliance with these requirements as they continue to evolve or their effect on our operations.
Properties that we acquire may not produce as projected and we may be unable to accurately predict reserve potential, identify liabilities associated with the properties, or obtain protection from sellers against such liabilities.
Acquisitions of producing and undeveloped properties have been an important part of our historical growth. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, including recoverable reserves, exploration or development potential, future oil and natural gas prices, operating costs, and potential environmental and other liabilities. We perform an engineering, geological and geophysical review of the acquired properties, which we believe is generally consistent with industry practices, and also endeavor to evaluate environmental risks. However, such assessments are inexact and their accuracy is inherently uncertain for a number of reasons. For instance, in connection with our assessments, such a review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not physically inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. Our review prior to signing a definitive purchase agreement may be even more limited. Often we are not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities associated with acquired properties. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. Additionally, properties previously acquired have not been subject to greenhouse gas requirements which have recently been adopted. As a result, significant unknown liabilities, including environmental liabilities, may exist and we may experience losses due to title defects in acquisitions for which we have limited or no contractual remedies or insurance coverage. These risks are magnified during a period of lower oil prices like we are currently experiencing in the United States. In addition, we may acquire oil and natural gas properties that contain economically recoverable reserves which are less than predicted. Thus, liabilities and uneconomically feasible oil and natural gas recoveries related to our acquisitions of producing and undeveloped properties may have a material adverse effect on our results of operations and reserve growth.
We cannot control the activities on properties we do not operate and we are unable to ensure the proper operation and profitability of these non-operated properties.
We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operation of these properties. The success and timing of drilling and development activities on our partially owned properties operated by others therefore will depend upon a number of factors outside of our control, including the operator’s:
•
timing and amount of capital expenditures;
•
expertise and diligence in adequately performing operations and complying with applicable agreements;
•
financial resources;
•
inclusion of other participants in drilling wells; and
•
use of technology.
As a result of any of the above or an operator’s failure to act in ways that are in our best interest, our allocated production revenues and results of operations could be adversely affected.
If the third parties we rely on for gathering and distributing our oil and natural gas are unable to meet our needs for such services and facilities, our future exploration and production activities could be adversely affected.
The marketability of our production depends upon the proximity of our reserves to, and the capacity of, third-party facilities and third-party services, including oil and gas gathering systems, pipelines, trucking or terminal facilities, and refineries or processing facilities. Such third parties are subject to federal and state regulation of the production and transportation of oil and gas. If such third parties are unable to comply with such regulations and we are unable to replace such service and facilities providers, we may be required to shut-in producing wells or delay or discontinue development plans for our properties. A shut-in, delay or discontinuance could adversely affect our financial condition.
The loss of our Chief Executive Officer or other key personnel could adversely affect our business.
We depend, and will continue to depend in the foreseeable future, on the services of Mark A. Fischer, our Chief Executive Officer, and other officers and key employees with extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and gas production, and developing and executing financing and hedging strategies. Our ability to retain our officers and key employees, or hire replacements if we should lose one or more, is important to our continued success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business.
Oil and gas drilling and production operations can be hazardous and may expose us to environmental or other liabilities.
Oil and gas operations are subject to many risks, including well blowouts, cratering, explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, hydraulic fracturing fluids, toxic gas or other pollutants and other environmental and safety hazards and risks. Our drilling operations involve risks from high pressures and from mechanical difficulties such as stuck pipes, collapsed casings and separated cables. If any of these events occur, we could sustain substantial losses as a result of:
•
injury or loss of life;
•
severe damage to or destruction of property, natural resources and equipment;
•
pollution or other environmental damage;
•
clean-up responsibilities;
•
regulatory investigations and administrative, civil and criminal penalties; and
•
injunctions or other proceedings that suspend, limit or prohibit operations.
Our liability for environmental hazards sometimes includes those created on properties prior to the date we acquired or leased them. While we maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover any or all resulting losses or liabilities. Moreover, if we experience more insurable events, our annual premiums may increase further or we may not be able to obtain any such insurance on commercially reasonable terms. The occurrence of, or failure by us to obtain or maintain adequate insurance coverage for, any of the events listed above could have a material adverse effect on our financial condition and results of operations, as well as our growth, exploration, and employee recruitment activities.
Costs of environmental liabilities could exceed our estimates and adversely affect our operating results.
Our operations are subject to numerous environmental laws and regulations, which obligate us to install and maintain pollution controls and to clean up various sites at which regulated materials may have been disposed of or released. It is not possible for us to estimate reliably the amount and timing of all future expenditures related to environmental matters because of:
•
the uncertainties in estimating clean up costs;
•
the discovery of additional contamination or contamination more widespread than previously thought;
•
the uncertainty in quantifying liability under environmental laws that impose joint and several liability on all potentially responsible parties;
•
changes in interpretation and enforcement of existing environmental laws and regulations; and
•
future changes to environmental laws and regulations and their enforcement.
Although we believe we have established appropriate reserves for known liabilities, including clean up costs, we could be required to set aside additional reserves in the future due to these uncertainties, incur material clean up costs, other liabilities, and/
or expend significant sums to defend ourselves against litigation related to legacy environmental issues, which could have an adverse effect on our operating results.
We may not be able to generate sufficient cash to service all of our long-term indebtedness, and we may be forced to take other actions to satisfy our obligations under our senior secured revolving credit facility, which may not be successful.
Our ability to make scheduled payments on or to refinance our debt obligations depends on our financial and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flow from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our long-term indebtedness.
If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to attempt to meet our debt service and other obligations. The indentures governing our senior notes and our senior secured revolving credit facility restrict our ability to use the proceeds from asset sales. We may not be able to consummate those asset sales to raise capital or to sell assets at prices that we believe are fair, and proceeds that we do receive may not be adequate to meet any debt service obligations then due.
If we cannot make scheduled payments on our long-term indebtedness, we will be in default and, as a result:
•
debt holders could declare all outstanding principal and interest to be due and payable;
•
we may be in default under our master (ISDA) derivative contracts and counterparties could demand early termination;
•
the lenders under the senior secured revolving credit facility could terminate their commitments to loan us money and foreclose against the assets securing their borrowings; and
•
we could be forced into bankruptcy or liquidation.
Our level of indebtedness may adversely affect our operations and limit our growth.
As of December 31, 2014, our total long-term indebtedness, including current maturities, was $1.6 billion. As of March 31, 2015, our total long-term indebtedness, including current maturities, was approximately $1.7 billion, and the borrowing base under our senior secured revolving credit facility was $650.0 million. Effective April 1, 2015, the borrowing base under our senior secured revolving credit facility was reduced from $650.0 million to $550.0 million. The borrowing base is based part on oil, natural gas and NGL prices and the value of our reserves. Many considerations, including but not limited to a significant decline in prices, a significant increase in operating costs, a downward revision of reserves, or other factors, could decrease our borrowing base. We may incur additional indebtedness, including significant secured indebtedness, in order to make future acquisitions or to develop our properties for production or for other purposes, and we expect to continue to be highly leveraged in the foreseeable future. Covenants set forth in the indentures for our senior notes, including the Adjusted Consolidated Net Tangible Asset debt incurrence test (the “ACNTA test”), limit the amount of secured debt we can incur. Certain thresholds set forth in the ACNTA test are principally reliant upon the levels of commodity prices for crude oil and gas at specified dates.
Our high level of indebtedness affects our operations in several ways, including the following:
•
the restrictions imposed on the operation of our business by the terms of our debt agreements may hinder our ability to take advantage of strategic opportunities to grow our business;
•
we must use a substantial portion of our cash flow from operations to pay interest on our senior notes and our other indebtedness, which reduces the funds available to us for operations and other purposes;
•
we may be at a competitive disadvantage compared to our competitors that may have proportionately less debt;
•
our ability to obtain additional financing for working capital, capital expenditures, debt service requirements, restructuring, acquisitions, or general corporate purposes may be impaired, which could be exacerbated by further volatility in the credit markets;
•
our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate may be limited;
•
we may be more vulnerable to economic downturns and adverse developments in our business; and
•
we may be vulnerable to interest rate increases, as our borrowings under our senior secured revolving credit facility are at variable rates.
Any of the foregoing could have a material adverse effect on our business, financial condition, results of operations, prospects, and ability to satisfy our debt obligations.
We may not have sufficient funds to repay bank borrowings if required as a result of a borrowing base redetermination.
Availability under our senior secured revolving credit facility is subject to a borrowing base, which will be $550 million as of April 1, 2015, and which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the banks may request a borrowing base redetermination once between each scheduled redetermination and in the event of early termination of our derivative contracts. If we issue Additional Permitted Debt, as defined in our senior secured revolving credit facility, the borrowing base will be automatically reduced by an amount equal to 25% of the aggregate stated principal amount of the debt issued, unless otherwise agreed to by our lenders. If the outstanding borrowings under our senior secured revolving credit facility were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay a portion of our bank borrowings in the amount of the excess either in a lump sum within 30 days or in equal monthly installments over a six-month period; (2) to submit within 30 days additional oil and gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and gas properties within 30 days. If we are forced to repay a portion of our bank borrowings, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.
Our use of derivative instruments could result in financial losses or reduce our income.
To reduce our exposure to the volatility in the price of oil and gas and provide stability to cash flows, we enter into derivative positions, some of which we had previously designated as cash flow hedges for accounting purposes. As of December 31, 2014, we had entered into commodity hedges covering 34,170 BBtu of our natural gas, 10,618 MBbls of our oil and natural gas liquids production for 2015 through 2016. Our commodity hedges are comprised of fixed price swaps, enhanced price swaps, basis protection swaps and three way collars. The volumes and average notional prices of these hedges are disclosed in “Note 6 -Derivative instruments” in Item 8. Financial Statements and Supplementary Data of this report. The fair value of our oil and gas derivative positions outstanding as of December 31, 2014 was an asset of approximately $251.6 million.
Derivative instruments expose us to risk of financial loss in some circumstances, including when:
•
our production is less than expected;
•
the counterparty to the derivative instruments defaults on its contractual obligations; or
•
there is a widening of price differentials between delivery points for our production and the delivery point assumed in the derivative instruments.
Derivatives also expose us to risk of income reduction as derivative instruments may limit the benefit we would receive from increases in the prices for oil and gas. Additionally, none of our derivatives are classified as hedges for accounting purposes and therefore must be adjusted to fair value through income each reporting period.
While the primary purpose of our derivative transactions is to protect us from the volatility in oil and natural gas prices, under certain circumstances, or if hedges are deemed ineffective, discontinued, or terminated for any reason, we may incur substantial losses in closing out our positions, which could have a material adverse effect on our financial condition, results of operations, and cash flows.
Our working capital could be adversely affected if we enter into derivative instruments that require cash collateral.
The use of derivatives may, in some cases, require the posting of cash collateral with counterparties (i.e. margin requirements). Although we currently do not, and do not anticipate that we will in the future, enter into derivative transactions that require an initial deposit of cash collateral, our working capital, and by extension, our growth, could be impacted if we enter into derivative transactions that require cash collateral and if commodity prices move in a manner adverse to us, we may be required to meet margin calls. Future collateral requirements are uncertain and will depend on arrangements with our counterparties and highly volatile oil and gas prices.
We are subject to financing and interest rate exposure risks.
Our future success depends on our ability to access capital markets and obtain financing on reasonable terms. Our ability to access financial markets and obtain financing on commercially reasonable terms in the future is dependent on a number of factors, many of which we cannot control, including changes in:
•
our credit ratings;
•
interest rates;
•
the structured and commercial financial markets;
•
market perceptions of us or the oil and gas exploration and production industry; and
•
our tax burden due to new tax laws.
Assuming a constant debt level of $650.0 million, equal to our borrowing base at December 31, 2014 (our only variable interest rate facility), the cash flow impact for a 12-month period resulting from a 100 basis point movement in interest rates, regardless of whether the spread widens or tightens, would be $6.5 million. As a result, any increases in our interest rates, or our inability to access the equity markets on reasonable terms, could have an adverse impact on our financial condition, results of operations, and growth prospects.
The concentration of accounts for our commodity sales, joint interest billings, or hedging with third parties could expose us to credit risk.
Substantially all of our accounts receivable result from commodity sales or joint interest billings to third parties in the energy industry. The concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, we have not experienced any material credit losses on our receivables. Future concentrations of sales of oil and gas to a limited number of customers, combined with decreases in commodity prices could result in adverse effects.
In addition, our oil and natural gas swaps or other hedging contracts expose us to credit risk in the event of non-performance by counterparties. Generally, these contracts are with major investment grade financial institutions and historically we have not experienced any credit losses. We believe that the guarantee of a fixed price for the volume of oil and natural gas hedged reduces volatility in our reported results of operations, financial position and cash flows from period to period and lowers our overall business risk. However, as also discussed along with other risks specific to hedging activities, we may be exposed to greater credit risk in the future.
Regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and gas.
The U.S. Congress has previously considered legislation to reduce emissions of greenhouse gases, including carbon dioxide, methane, and nitrous oxide among others, which some studies have suggested may be contributing to warming of the earth’s atmosphere. However, federal legislation to reduce greenhouse gases appears uncertain. As a result, regulation of greenhouse gases will continue to result primarily from regulatory action by the Environmental Protection Agency (EPA) or by the several states that have already taken legal measures to reduce emissions of greenhouse gases.
Federal regulation. EPA has adopted regulations requiring Clean Air Act (“CAA”) permitting of greenhouse gas emissions from stationary sources. As a result of the U.S. Supreme Court’s decision in Massachusetts, et al. v. EPA finding that greenhouse gases fall within the CAA’s definition of “air pollutant,” the EPA was required to determine whether concentrations of greenhouse gases in the atmosphere “endanger” public health or welfare, and whether emissions of greenhouse gases from motor vehicles may “cause or contribute” to this endangerment. On December 15, 2009, EPA promulgated its final rule, “Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act”. On May 7, 2010, EPA and the Department of Transportation’s National Highway Traffic and Safety Administration, or NHTSA, promulgated a final action establishing a national program providing new standards for certain motor vehicles to reduce greenhouse gas emissions and improve fuel economy. While these motor vehicle regulations do not directly impact oil and gas production operations, they can automatically trigger application of the Prevention of Significant Deterioration (“PSD”) and Title V Operating Permit programs for stationary sources of greenhouse gas emissions, potentially including oil and gas production operations. On June 3, 2010, EPA promulgated its “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule,” to add new higher thresholds of 75,000 tons per year carbon dioxide equivalents (“CO2e”) for modifications to existing sources and 100,000 tons per year CO2e for new sources.
EPA has promulgated separate regulations requiring greenhouse gas emission reporting from certain industry sectors, including natural gas production. On October 30, 2009, EPA promulgated a final mandatory greenhouse gas reporting rule which will assist EPA in developing policy approaches to greenhouse gas regulation. This reporting rule became effective on December 29, 2009. On November 30, 2010, EPA promulgated additional mandatory greenhouse gas reporting rules that apply specifically to oil and gas production for implementation in 2011.
On August 16, 2012, EPA promulgated new CAA regulations addressing volatile organic compounds (VOCs) and other criteria pollutants, “Oil and Natural Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews.” These new rules are intended to broaden the current scope of EPA’s regulation to include standards governing emissions from most operations associated with oil and natural gas production facilities, natural gas transmission and storage facilities. EPA states that greenhouse gases will be controlled indirectly as a result of these new rules. Among other things, these new rules require the use of reduced emission completions or “green completions” on all hydraulically
fractured gas wells completed or refractured after January 1, 2015. They also set new requirements for emissions from compressors, controllers, dehydraters, storage vessels and other affected production equipment.
Recent case law. Beyond legislative and regulatory developments, litigation against energy industry sectors emitting greenhouse gases have arisen based upon common law claims, that may expose us, as a potentially source of significant direct and indirect emission of greenhouse gases, to similar litigation risk.
International treaties. Other nations have already agreed to regulate emissions of greenhouse gases pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the United States) agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012.
International developments, passage of state or federal climate control legislation or other regulatory initiatives, the adoption of regulations by EPA and analogous state agencies that restrict emissions of greenhouse gases in areas in which we conduct business, or development of caselaw allowing claims based upon greenhouse gas emissions, could have an adverse effect on our operations and financial condition as a result of material increases in operating and production costs and litigation expense due to expenses associated with monitoring, reporting, permitting and controlling greenhouse gas emissions or litigating claims related to emissions of greenhouse gases, as well as reduced demand for fossil fuels generally.
Potential legislative and regulatory actions could increase our costs, reduce our revenue and cash flow from commodity sales, reduce our liquidity or otherwise alter the way we conduct our business.
In recent years the administration of President Obama made budget proposals which, if enacted into law by Congress, would potentially increase and accelerate the payment of federal income taxes by independent producers of oil and gas. Proposals have included, but have not been limited to, repealing the enhanced oil recovery credit, repealing the credit for oil and gas produced from marginal wells, repealing the expensing of intangible drilling costs, repealing the deduction for the cost of qualified tertiary expenses, repealing the exception to the passive loss limitation for working interests in oil and gas properties, repealing the percentage depletion allowance, repealing the manufacturing tax deduction for oil and gas companies, and increasing the amortization period of geological and geophysical expenses. In 2009, 2010, and 2011, legislation which would have implemented the proposed changes was introduced but not enacted. It is unclear whether legislation supporting any of the above described proposals, or designed to accomplish similar objectives, will be introduced or, if introduced, would be enacted into law or, if enacted, how soon resulting changes would become effective. However, the passage of any legislation designed to implement changes in the U.S. federal income tax laws similar to the changes included in the budget proposals offered by the White House in in recent years could eliminate certain tax deductions currently available with respect to oil and gas exploration and development, and any such changes (i) could make it more costly for us to explore for and develop our oil and gas resources and (ii) could negatively affect our financial condition and results of operations.
Competition for experienced technical personnel may negatively impact our operations or financial results.
Our continued drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced explorationists, engineers and other professionals. Competition for these professionals remains strong and we are likely to continue to experience increased costs to attract and retain these professionals. Retention of our current employees is made more critical in light of our recent workforce reduction. Following the recent drop in oil and natural gas prices, in an effort to reduce costs and better position ourselves for ongoing efficient growth, we committed to a Company-wide restructuring that included a workforce reduction of 121 employees in our headquarters office and the release of approximately 59 field personnel.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing and waste water injector wells could result in increased costs and additional operating restrictions or delays.
Congress has previously considered legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. Sponsors of bills previously considered before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which is already required by some state agencies governing our operations. Such disclosure could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, these bills, if adopted, could repeal the exemptions for hydraulic fracturing from the Safe Drinking Water Act.
These federal legislative efforts have slowed while EPA studies the issue of hydraulic fracturing. In 2010, EPA initiated a Hydraulic Fracturing Research Study to address concerns that hydraulic fracturing may affect the safety of drinking water, as well as review the application of other environmental statutes to hydraulic fracturing activities, including the RCRA and the Clean
Water Act. As part of that process, EPA requested and received information from the major fracturing service providers regarding the chemical composition of fluids, standard operating procedures and the sites where they engage in hydraulic fracturing. In February 2011, EPA released its Draft Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources, proposing to study the lifecycle of hydraulic fracturing fluid and providing a comprehensive list of chemicals identified in fracturing fluid and flowback/produced waste. EPA expects to release a draft assessment report for peer review and comment in early 2015.
We conduct oil and natural gas exploration, development and drilling activities in Oklahoma and elsewhere. In recent years, Oklahoma has experienced a significant increase in earthquakes and other seismic activity. Some parties believe that there is a correlation between the operation of underground injection wells for the disposal of produced water and the increased occurrence of earthquakes. The extent of this correlation, if any, is the subject of studies by both state and federal agencies, the results of which remain uncertain.
These developments, as well as increased scrutiny of hydraulic fracturing and underground injection activities by state and municipal authorities may result in additional levels of regulation or complexity with respect to existing regulations that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.
Increased regulatory requirements regarding CO2 pipeline integrity may require us to incur significant capital and operating expenses to comply.
The ultimate costs of compliance with CO2 pipeline integrity regulations are difficult to predict. The majority of the compliance costs are for pipeline integrity testing and the repairs found to be necessary. We plan to continue our efforts to assess and maintain the integrity of our existing and future pipelines as required by the U.S. DOT rules. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our CO2 pipelines. In addition, new laws and regulations that may be enacted in the future, or a revised interpretation of existing laws and regulations, could significantly increase the amount of these costs. We cannot be assured about the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs, or additional operating restrictions, could have a material adverse effect on our business, financial position, results of operations and prospects.
We are responsible for the decommissioning, abandonment, and reclamation costs for our facilities, which could decrease funds available for servicing our debt obligations and other operating expenses.
We are responsible for compliance with all applicable laws and regulations regarding the decommissioning, abandonment and reclamation of our facilities at the end of their economic life, the costs of which may be substantial. It is not possible to predict these costs with certainty since they will be a function of regulatory requirements at the time of decommissioning, abandonment and reclamation. We may, in the future, determine it prudent or be required by applicable laws or regulations to establish and fund one or more decommissioning, abandonment and reclamation reserve funds to provide for payment of future decommissioning, abandonment and reclamation costs, which could decrease funds available to service debt obligations. In addition, such reserves, if established, may not be sufficient to satisfy such future decommissioning, abandonment and reclamation costs and we will be responsible for the payment of the balance of such costs.
Unusual weather patterns or natural disasters, whether due to climate change or otherwise, could negatively impact our financial condition.
Our business depends, in part, on normal weather patterns across the United States. Natural gas demand and prices are particularly susceptible to seasonal weather trends. Warmer than usual winters can result in reduced demand and high season-end storage volumes, which can depress prices to unacceptably low levels. In addition, because a majority of our properties are located in Oklahoma,Texas and Louisiana, our operations are constantly at risk of extreme adverse weather conditions such as freezing rain, tornadoes and hurricanes. Any unusual or prolonged adverse weather patterns in our areas of operations or markets, whether due to climate change or otherwise, could have a material and adverse impact on our business, financial condition and cash flow. In addition, our business, financial condition and cash flow could be adversely affected if the businesses of our key vendors, purchasers, contractors, suppliers or transportation service providers were disrupted due to severe weather, such as freezing rain, hurricanes or floods, whether due to climate change or otherwise.
Climate change and government laws and regulations related to climate change could negatively impact our financial condition.
Scientific studies suggest emissions of certain gases, commonly referred to as "greenhouse gases" ("GHGs") and including carbon dioxide and methane, may contribute to warming of the earth's atmosphere and other climatic changes. In response to such studies, Congress has from time to time considered legislation to reduce emissions of GHGs. One bill approved
by the House of Representatives in June 2009, known as the American Clean Energy and Security Act of 2009, would have required an 80% reduction in emissions of GHGs. In addition. Many states have taken measures to reduce emissions of GHGs through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. Some states have enacted renewable portfolio standards, which require utilities to purchase a certain percentage of their energy from renewable fuel sources.
In addition, in December 2009, the EPA determined that emissions of carbon dioxide, methane and other "greenhouse gases" ("GHGs") present an endangerment to human health and the environment, because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. In response to its endangerment finding, the EPA adopted two sets of rules regarding possible future regulation of GHG emissions under the Clean Air Act. The motor vehicle rule, which became effective in January 2011, purports to limit emissions of GHGs from motor vehicles. The EPA adopted the stationary source rule (or the "tailoring rule") in May 2010, and it became effective in January 2011. The tailoring rule established new GHG emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration (“PSD”) and Title V of the Clean Air Act. In June 2014, the Supreme Court held that stationary sources could not become subject to Title V permitting solely by reason of their GHG emissions. However, the Court also ruled the EPA may require installation of best available control technology for GHG emissions at sources otherwise subject to the PSD and Title V programs. On December 19, 2014, the EPA issued initial guidance on GHG permitting requirements in response to the Court's decision. In its preliminary guidance, the EPA indicated it will undertake a rulemaking action no later than December 31, 2015 to rescind any PSD permits issued under the portions of the tailoring rule that were vacated by the Court. In the interim, the EPA issued a narrowly crafted "no action assurance" indicating it will exercise its enforcement discretion not to pursue enforcement of the terms and conditions relating to GHGs in an EPA-issued PSD permit, and for related terms and conditions in a Title V permit.
In September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA published a final rule expanding the GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. In December 2014, the EPA published a proposed rule to amend the GHG Reporting Program to add reporting of GHG emissions from gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines. The rule underwent an extended public comment period, which closed on February 24, 2015.
The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations.
In addition to other climate-related risks set forth in this “Risk Factors” section, we are and will be, directly and indirectly, subject to the effects of climate change and are, and most likely will continue to be, affected by government laws and regulations related to climate change. We are currently evaluating compliance costs arising from newly adopted mandatory greenhouse gas reporting rules, and potential compliance costs arising from newly promulgated Clean Air Act reporting and permit regulations for greenhouse gas emissions. These new regulations could be preempted by new federal legislation if enacted. However, we cannot predict with any degree of certainty the ultimate effect possible climate change and government laws and regulations related to climate change will have on our operations. While it is difficult to assess the timing and effect of climate change and pending legislation and regulation related to climate change on our business, we believe that climate change and government laws and regulations related to climate change may affect: (i) the cost of the equipment and services we purchase, (ii) our ability to continue to operate as we have in the past, including drilling, completion and operating methods, (iii) the timeliness of delivery of the materials and services we need and the cost of transportation paid by us and our vendors and other providers of services, (iv) insurance premiums, deductibles and the availability of coverage, (v) the cost of utility services, particularly electricity, in connection with the operation of our properties, and (vi) factors arising from new Clean Air Act greenhouse gas permitting and, or, possible greenhouse gas legislation, in addition to previously identified factors. These potential effects depend upon, but are not limited to, the following considerations: whether and to what extent legislation is enacted, the nature of the legislation (such as a cap and trade system or a tax on emissions); the greenhouse gas reductions required pursuant to either existing Clean Air Act
regulatory requirements or new greenhouse gas legislation; the cost and availability of required offsets or emissions reductions; the amount and allocation of possible allowances; costs required to improve facilities and equipment to both monitor and reduce emissions in order to comply with regulatory limits or to mitigate the financial consequences of a greenhouse gas emission limitations; changes to profit or loss arising from increased or decreased demand for oil and gas we produce arising directly from legislation or regulation, and indirectly from changes in production costs. In addition, climate change may increase the likelihood of property damage and the disruption of our operations, especially in coastal states. As a result, our financial condition could be negatively impacted by significant climate change and related governmental regulation, and that impact could be material.
The adoption of The Dodd-Frank Wall Street Reform and Consumer Protection Act could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price and other risks associated with our business.
In July of 2010, the U.S. Congress enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), which contains measures aimed at increasing the transparency and stability of the over-the-counter (“OTC”) derivative markets and preventing excessive speculation. Certain companies that use swaps or other derivatives to hedge commercial risk, referred to as end-users, are permitted to continue to use OTC derivatives under newly adopted regulations. We maintain an active price and basis protection hedging program related to the natural gas and oil we produce to manage the risk of low commodity prices and to predict with greater certainty the cash flow from our hedged production. We have used the OTC market exclusively for our natural gas and oil derivative contracts. The Dodd-Frank Act and the rules and regulations promulgated thereunder should permit us, as an end user, to continue to utilize OTC derivatives. However, we may have increased costs or reduced liquidity in the OTC derivatives market due to the current or future regulations. Such changes could materially reduce our hedging opportunities and negatively affect our revenues and cash flow during periods of low commodity prices.
The listing of a species as either “threatened” or “endangered” under the federal Endangered Species Act could result in increased costs and new operating restrictions, loss of leasehold or delays on our operations, which could adversely affect our results of operations and financial condition.
The federal Endangered Species Act (“ESA”) and analogous state laws regulate a variety of activities that may have an
adverse effect on species listed as threatened or endangered under the ESA or their habitats. The designation of previously
unidentified endangered or threatened species in areas where we operate could cause us to incur additional costs or become subject
to operating delays, restrictions or bans. Numerous species have been listed or proposed for protected status in areas in which we
currently, or could in the future, undertake operations. For instance, the American Burying Beetle and the Lesser Prairie Chicken
both have habitat in some areas where we operate. The presence of these protected species in areas where we
operate could impair our ability to timely complete or carry out those operations, lose leaseholds as we may not be permitted to
timely commence drilling operations, cause us to incur increased costs arising from species protection measures, and,
consequently, adversely affect our results of operations and financial position.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
See Item 1. Business and Properties. We also have various operating leases for rental of office space, office and field equipment, and vehicles. See our additional disclosures in “Liquidity and Capital Resources-Contractual Obligations” in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, as well as “Note 13 - Commitments and contingencies” in Item 8. Financial Statements and Supplementary Data. Such information is incorporated herein by reference.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Naylor Farms, Inc., individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On June 7, 2011, an alleged class action was filed against us in the United States District Court for the Western District of Oklahoma (“Naylor Farms Case”) alleging that we improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners as categorized in the petition from crude oil and natural gas wells located in Oklahoma. The purported class includes non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. The plaintiffs have alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. We have responded to the Naylor Farms petition, denied the allegations and raised arguments and defenses. Discovery is ongoing and information and documents continue to be exchanged. The class has not been certified, but the motion for class certification is due in the fourth quarter of 2015. We are not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the Naylor Farms Case will have on our financial condition, results of operations or cash flows due to the preliminary status of the matters, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the potential size of the class, the scope and types of the properties and agreements involved, and the ultimate potential outcome of the matter. Plaintiffs in the Naylor Farms Case have indicated, that if the class is certified, they seek damages in excess of $5 million which may increase with the passage of time, a majority of which would be comprised of interest. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.
Amanda Dodson, individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On May 10, 2013, Amanda Dodson (the “Plaintiff”), filed a complaint against us in the District Court of Mayes County, Oklahoma, (“Dodson Case”) with allegation similar to those asserted in the Naylor Farms case related to post-production deductions, and include clams for breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. The alleged class includes non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. We have responded to the Dodson petition, denied the allegations and raised a number of affirmative defenses. At this time, a class has not been certified and discovery has not yet commenced. We are not currently able to estimate a reasonable possible loss or range of loss or what impact, if any, the Dodson Case will have on its financial condition, results of operations or cash flows due to the preliminary status of the matters, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the potential size of the class, the scope and types of the properties and agreements involved, and the ultimate potential outcome of the matter. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.
Martha Donelson and John Friend, on behalf of themselves and on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On August 11, 2014, an alleged class action was filed against us, as well as several other operators in Osage County, in the United States District Court for the Northern District of Oklahoma (“Donelson Case”), alleging claims on behalf of the named plaintiffs and all similarly situated Osage County land owners and surface lessees. The Plaintiffs assert claims seeking recovery for trespass, nuisance, negligence and unjust enrichment. Relief sought includes declaring oil and natural gas leases and drilling permits obtained in Osage County without a prior NEPA study void ab initio, removing us from all properties owned by the class members, disgorgement of profits, and compensatory and punitive damages. We have joined in Motions to Dismiss filed by the Defendants. At this time, a class has not been certified and discovery has yet to begin. As such, we are not yet able to estimate a possible loss, or range of possible loss, if any. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.
We are involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, employment claims, and other matters which arise in the ordinary course of business. While the outcome of these legal proceedings cannot be predicted with certainty, we do not expect any of them individually to have a material effect on our financial condition, results of operations or cash flows.
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
Our common stock has not been registered under the Securities Exchange Act of 1934, and there is no established public trading market for our common equity.
As of March 31, 2015, we had 1,411,572 shares of common stock outstanding held by 31 record holders.
We have not paid any dividends on our common stock in either of the last two years and we do not currently anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any future determination relating to our dividend policy will be at the discretion of our board of directors and will depend on our results of operations, financial condition, capital requirements and other factors deemed relevant by our board. We are also currently restricted in our ability to pay dividends under our senior secured revolving credit facility. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources for more information regarding the restrictions on our ability to pay dividends.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
You should read the following historical financial data in connection with the financial statements and related notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in this report. The financial data as of and for each of the five years ended December 31, 2014 was derived from our audited financial statements. Our historical results are not necessarily indicative of results to be expected in future periods.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the accompanying notes included elsewhere in this report. In addition to historical financial information, the following discussion contains forward-looking statements that reflect our plans, estimates, and beliefs. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to these differences include those discussed below and elsewhere in this report, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”
Overview
Founded in 1988, we are an independent oil and natural gas exploration and production company headquartered in Oklahoma City, Oklahoma and are one of the largest oil producers in the state. In recent years, we have capitalized on our sustained success in our Mid-Continent area, expanding our holdings to become a leading player in both the liquids-rich Northern Oklahoma Mississippian and the oil-rich Panhandle Marmaton plays. In addition, we have a leadership position in CO2 EOR and are now the third largest CO2 EOR operator in the United States based on the number of active projects. This position is underscored by our activity in the North Burbank Unit in Osage County, Oklahoma, which is the single largest oil recovery unit in the state.
As of December 31, 2014, we had estimated proved reserves of 159.4 MMBoe with a PV-10 value of approximately $2.5 billion. These estimated proved reserves included 57.5 MMBoe of active EOR reserves. Our reserves were 58% proved developed, 64% crude oil, and 11% natural gas liquids.
Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas and on our ability to find, develop and acquire oil and natural gas reserves that are economically recoverable. The preparation of our financial statements in conformity with generally accepted accounting principles (“GAAP”) requires us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved oil and natural gas reserves. We use the full cost method of accounting for our oil and natural gas activities.
Generally, our producing properties have declining production rates. Our December 31, 2014 reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 21%, 14%, and 12% for the next three years. To grow our production and cash flow, we must find, develop and acquire new oil and natural gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire oil and natural gas reserves.
Oil and natural gas prices fluctuate widely. We generally hedge a substantial portion of our expected future oil and natural gas production to reduce our exposure to commodity price decreases. The prices we receive for our oil and natural gas production affect our:
•
cash flow available for capital expenditures;
•
ability to borrow and raise additional capital;
•
ability to service debt;
•
quantity of oil and natural gas we can produce;
•
quantity of oil and natural gas reserves; and
•
operating results for oil and natural gas activities.
Business and Industry Outlook
Crude oil prices decreased significantly in the latter part of 2014 and have continued to trend lower in 2015, dropping to their lowest levels since March 2009. Management's plans and related capital projections for 2015 are reflective of lower commodity prices.
In response to the decrease in crude oil prices, in February 2015 we began implementation of a Company-wide effort to decrease our capital, operating and administrative costs. Our cost savings initiatives included a reduction in our workforce by 180 employees, including 121 located in the Oklahoma City headquarters office and 59 located at various field offices. In connection with our workforce reduction, we estimate that we will record a charge of $6.6 million million during the first quarter of 2015 related to one-time severance and termination benefits.
Given the weak commodity price environment, we are aggressively pursuing price concessions from third-party service vendors. Based on expected cost reductions from service providers and improved operational efficiencies, we anticipate decreases of 15% - 30% in drilling and completion costs and 10% - 30% in lease operating expenses for 2015. We are continuing negotiations with our vendors to receive the best possible pricing.
Our cost savings initiatives described above have required us to engage third party legal and professional services for which we have incurred approximately $2.3 million for the three months ended March 31, 2015. As discussed below in “Liquidity and capital resources,” we are allowed to exclude up to $25.0 million of expenses incurred in connection with our cost restructuring initiatives, including costs related to our workforce restructuring, from our EBITDA-based covenant under our senior secured revolving credit facility.
We have significantly reduced our 2015 capital expenditures budget to $177.3 million, nearly one quarter the amount spent in 2014. We expect our operated rig count to average 2 rigs for full-year 2015, down from 10 operated rigs at December 31, 2014. While we plan to scale back our 2015 drilling, we plan to continue the momentum of our long-term growth projects in our Mid-Continent area by focusing our drilling efforts in core areas of those plays that have the greatest potential to improve recoveries and rates of return.
Our 2015 capital budget has been established based on an expectation of available cash flows from operations and availability under our credit facility. We will continue to monitor our capital spending closely based on actual and projected cash flows and could scale back our 2015 spending further should commodity prices remain at current levels or fall further. Conversely, a significant improvement in crude oil prices could result in an increase in our capital expenditures.
We deal with volatility in commodity prices primarily by maintaining flexibility in our capital investment program with a diversified drilling portfolio and limited long-term commitments, which enables us to respond quickly to industry volatility, as well as aggressively pursue cost reductions in a market downturn. However, price volatility impacts our business in various other ways including our full cost ceiling test calculation. The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending on the balance sheet date. For the year ended December 31, 2014, those prices were $94.99 per Bbl for oil and $4.35 per MMBtu for natural gas, while the unweighted arithmetic average price of crude oil and natural as of the first day of each month for the 12-month period through March 2015 were $82.72 per Bbl and $3.88 per MMBtu, respectively. If commodity prices remain at decreased levels, the average prices used in the ceiling test calculation will decline and will likely cause potential write downs of our oil and natural gas properties. Due to the substantial decline of commodity prices during the third and fourth quarters of 2014, which have remained low during the first quarter of 2015, we anticipate that we will have a ceiling test write-down during 2015. Continued write downs of oil and natural gas properties may occur until such time as commodity prices recover, and remain at recovered levels, so as to meaningfully increase the 12-month average price used in the ceiling test calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.
2014 Highlights
The following are material events that have impacted our liquidity or results of operations, and/or are expected to impact these items in future periods:
•
Asset sales. We completed the sale of two separate divestiture packages of non-core properties during the second quarter of 2014 for $148.4 million in cash, net of post-closing adjustments. In July 2014, we completed the sale of two additional divestiture packages of non-core properties for $95.9 million in cash, net of post-closing adjustments. The properties included in these four sales accounted for approximately 6% and 15% of our total production during 2014 and 2013, respectively. In addition to the packages described above, we also received approximately $44.5 million in cash for various other property divestitures during 2014.
•
Senior secured revolving credit facility and liquidity. The initial borrowing base on our senior secured revolving credit facility for 2014 was $600.0 million. In May 2014, our senior secured revolving credit facility was amended to automatically reduce the borrowing base in tandem with the completion of our oil and natural gas property divestitures. As a result of two divestitures that closed during the second quarter and two additional divestitures that closed in July 2014, our borrowing base was reduced to $484.5 million effective July 18, 2014. Our semiannual redetermination, effective November 5, 2014, increased our borrowing base to $650.0 million. Our lenders have completed the semi-annual borrowing base redetermination originally scheduled for May 1, 2015, which has resulted in a decrease of our borrowing base to $550.0 million to be effective on April 1, 2015. We had approximately $199.1 million of borrowing availability on our senior secured credit facility at March 30, 2015.
•
Capital expenditures. Our oil and natural gas property capital expenditure budget for 2015 is set at $177.3 million. We continued to focus on drilling in our repeatable resource plays in the Mid-Continent area and continued our focus on the acquisition of prospect acreage and drilling opportunities in these plays. Our drilling expenditures in the Mid-Continent area for 2014 increased from $272.0 million in 2013 to $434.9 million in 2014, and we have allocated $97.7 million for drilling in 2015. Our expenditures for EOR increased from $151.8 million in 2013 to $194.6 million in 2014, and we have budgeted $49.6 million for the development of our EOR assets in 2015.
Results of operations
Overview
Total production, commodity sales, and cash flow increased each year from 2012 to 2014. During 2014, revenue increased by 15% compared to 2013 primarily as a result of increased oil and natural gas production, higher natural gas and NGL prices and a continuing shift in our commodity sales mix towards liquids. This increase in 2014 from 2013 was combined with a $253.0 million increase in our non-hedge derivative gains, which was primarily due to the significant volatility of oil and natural gas prices and changes in our outstanding derivatives contracts during these periods. Revenue in 2013 increased by 16% compared to 2012 primarily as a result of higher oil and natural gas prices combined with increased oil and natural gas production. As a result of these and other transactions discussed below, we had net income in 2014, 2013 and 2012 of $209.3 million, $55.7 million, and $64.4 million, respectively.
Revenues and production
The following table presents information about our commodity sales before the effects of commodity derivative settlements:
Commodity sales increased $89.9 million, or 15%, to $681.6 million during 2014 from 2013 due to a 13% increase in sales volumes combined with a 2% increase in the average price per Boe. Oil production for 2014 increased compared to 2013 primarily due to drilling and development activity in our NOMP and Panhandle Marmaton play, which together accounted for approximately 31% and 18% of our total oil production during 2014 and 2013, respectively. Natural gas production for 2014 increased compared to 2013 primarily due to our drilling and development activity in our NOMP, which accounted for approximately 34% and 19% of our total natural gas production during 2014 and 2013, respectively. Natural gas liquids production for 2014 increased compared to 2013 primarily due to increased drilling and development activity in our NOMP.
Commodity sales increased $82.2 million, or 16%, to $591.7 million during 2013 from 2012 due to a 9% increase in the average price per Boe combined with a 7% increase in sales volumes. Oil production for 2013 increased compared to 2012 primarily due to drilling and development activity in our NOMP and Panhandle Marmaton play, which together accounted for approximately 18% and 7% of our total oil production during 2013 and 2012, respectively. Natural gas production for 2013 increased compared to 2012 primarily due to our drilling and development activity in our NOMP, which accounted for approximately 19% and 6% of our total natural gas production during 2013 and 2012, respectively. Natural gas liquids production for 2013 increased compared to 2012 primarily due to increased drilling and development activity in our NOMP.
The relative impact of changes in commodity prices and sales volumes on our commodity sales before the effects of hedging is shown in the following table:
Production volumes by area were as follows (MBoe):
The increase in production in our E&P Areas is primarily due to our drilling and development activities in our NOMP and Panhandle Marmaton plays, slightly offset by decreased production in our Legacy Production Areas. The Mississippian and Panhandle Marmaton plays accounted for approximately 33%, 18%, and 6% of our total production during 2014, 2013, and 2012, respectively. The decrease in production in our Legacy Production Areas is primarily due to divestitures and the natural decline in production as we invested our resources in the Mississippian and Panhandle Marmaton plays and active EOR projects during 2014.
Production in our EOR Project Areas increased primarily due to response from our CO2 injection activities in our Farnsworth Area and North Burbank Units.
The decrease in production in our Non-Core Properties is primarily due strategic divestitures within these areas combined with normal depletion of the reservoirs. During 2014, we closed on the majority of the previously announced strategic divestitures of our remaining Non-Core Properties in the Permian Basin, Ark-La-Tex, and North Texas areas.
Derivative activities
Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into commodity price swaps, costless collars, put options, and basis protection swaps. These derivative instruments allow us to predict with greater certainty the effective prices we will receive for associated oil and natural gas production. We also enter into crude oil derivative contracts for a portion of our natural gas liquids production.
We closely monitor the fair value of our derivative contracts and may elect to settle a contract prior to its scheduled maturity date in order to lock in a gain or loss.
Our realized prices are impacted by realized gains and losses resulting from commodity derivatives contracts. The following table presents information about the effects of derivative settlements on realized prices:
The estimated fair values of our oil and natural gas derivative instruments are provided below. The associated carrying values of these instruments are equal to the estimated fair values.
The effects of derivative activities on our results of operations and cash flows were as follows:
We no longer apply hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as non-hedge derivative gains (losses) in our consolidated statements of operations. Gain from oil hedging activities, which is a component of total revenues in our consolidated statements of operations, of nil, $37.1 million, and $46.7 million for 2014, 2013, and 2012, respectively, consists of the reclassification of hedge gains on discontinued oil hedges from accumulated other comprehensive income into net income.
The fluctuation in non-hedge derivative gains (losses) from period to period is due primarily to the significant volatility of oil and natural gas prices and basis differentials and to changes in our outstanding derivative contracts during these periods. Net gains (losses) on derivative activities recognized in our statements of operations were $231.3 million, $15.5 million, and $96.4 million in 2014, 2013, and 2012, respectively.
Lease operating expenses
Lease operating costs are sensitive to changes in demand for field equipment, services, and qualified operational personnel, which is driven by demand for oil and natural gas. However, the timing of changes in operating costs may lag behind changes in commodity prices. Our EOR projects are more expensive to operate than traditional industry operations due to the nature of operations along with the costs of recovery and recycling of CO2.
Our E&P Areas lease operating expenses decreased slightly during 2014 compared to 2013, primarily as a result of the divestiture of certain non-core assets with higher operating costs partially offset by the incremental cost of oil field goods and services associated with new wells added during 2014. Our lease operating expenses on a Boe basis decreased significantly in 2014 compared to 2013 primarily as a result of the increase in overall production volumes between periods as well as the impact of our divestiture of our non-core higher operating cost properties.
Our EOR Project Areas lease operating expenses increased during 2014 compared to 2013, due primarily to additional costs associated with expansion of our EOR floods at our North Burbank and Farnsworth units. While production for our North Burbank unit increased compared to 2013, its production remains relatively low because production is still ramping up, resulting in higher per-barrel operating costs. As we are now observing a more pronounced response, we expect per-barrel operating costs for our North Burbank unit to decrease in 2015.
Our E&P Areas lease operating expenses in 2013 increased when compared to 2012 primarily due to the additional cost of oil field goods and services associated with new wells added during 2013, offset by decreased operating expenses due to the divestiture of certain non-core assets. Our lease operating expenses on a Boe basis, however, decreased in 2013 compared to 2012. The slight decrease in lease operating costs per Boe is due to the 7% increase in production, which more than offset our higher lease operating expenses.
Our EOR Project Areas lease operating expenses increased during 2013 compared to 2012 levels, due primarily to additional costs associated with expansion of our CO2 EOR floods including our newest CO2 EOR flood at our North Burbank unit which commenced CO2 injection and recycling in June of 2013, as well as its production being relatively low to operating costs because North Burbank’s CO2 uplift was not that material in 2013, resulting in higher per-barrel operating costs, which is typical when we startup a new CO2 EOR flood.
Production taxes (which include ad valorem taxes)
Production taxes generally change in proportion to commodity sales. Some states offer exemptions or reduced production tax rates for horizontal drilling, enhanced recovery projects and high cost gas wells. In Oklahoma, new wells qualify for a tax incentive and are taxed at a lower rate during their initial months of production. After the incentive period expires, the tax rate reverts to the statutory rate.
The 2014 decrease in production taxes from 2013 was primarily due to our strategic divestitures of wells in our Non-Core Properties and Legacy Production Areas, which generally had higher tax rates, combined with reduced tax rates for horizontal drilling along with EOR and high cost gas exemption tax credits, partially offset by the 13% increase in sales volumes combined with the 2% increase in averaged realized prices.
The 2013 increase in production taxes from 2012 was primarily due to the 16% increase in commodity sales, partially offset by lower tax rates on our horizontal wells and by EOR tax credits.
Depreciation, depletion and amortization (“DD&A”) and losses on impairment
We adjust our DD&A rate on oil and natural gas properties each quarter for significant changes in our estimates of oil and natural gas reserves and future costs, and thus our DD&A rate could change significantly in the future. DD&A on oil and natural gas properties increased $52.0 million from 2013 to 2014, of which $29.1 million was due to a higher rate per equivalent unit of production and $22.9 million was due to the increase in production. Our DD&A rate per equivalent unit of production increased $2.65 to $21.10 per Boe primarily due to higher estimated future development costs for proved undeveloped reserves and higher cost reserve additions.
DD&A on oil and natural gas properties increased $24.9 million from 2012 to 2013, of which $14.3 million was due to a higher rate per equivalent unit of production and $10.6 million was due to the increase in production. Our DD&A rate per equivalent unit of production increased $1.47 to $18.45 per Boe primarily due to higher cost reserve additions for development and acquisitions and higher estimated future development costs for proved undeveloped reserves.
We record the estimated future value of a liability for an asset retirement obligation in the period in which it is incurred, discounted to its present value using our credit adjusted risk-free interest rate, with a corresponding increase in the carrying amount of oil and natural gas properties. The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset.
Property impairments. Impairments of non-producing properties, which results in a transfer of amounts from unevaluated oil and natural gas properties to proved oil and natural gas properties, increased $56.9 million in 2014 to $63.4 million, including $23.4 million recognized in the fourth quarter as a result of changes in management’s estimates of undeveloped properties not expected to be developed before lease expiration in response to the significant decrease in crude oil prices which has altered our drilling plans combined with lower than expected results for certain exploratory activities in our Panhandle Marmaton area.
Impairment of other assets. There was no impairment losses on other assets for the year ended December 31, 2014. In 2013, we recognized $3.5 million of impairment losses on certain of our owned drilling rigs due to our expectation that these rigs may not sell at a price that will exceed their carrying values. These rigs were initially classified as held for sale in 2012 but were reclassified to property and equipment at the end of 2013. An initial impairment loss of $1.5 million was recognized on these rigs in 2012. Also in 2012, we recognized $0.5 million of additional impairment losses primarily related to drill pipe.
General and administrative expenses (“G&A”)
Gross G&A expenses in 2014 increased from 2013 primarily due to increased compensation and benefits costs related to the competitive nature of our market and our growing operations, along with other expenses and general inflation. Stock-based compensation expense included in G&A for 2014 was $3.7 million.
Capitalized exploration and development costs increased between periods primarily due to a higher proportion of compensation costs subject to capitalization. A larger proportion of our compensation costs are being capitalized compared to the prior period as a result of our shift in focus from acquiring developed properties to exploring and developing leasehold acreage in resource plays with repeatable drilling opportunities.
Our G&A expenses on a Boe basis, however, decreased from 2013 to 2014 primarily due to the increase in overall production volumes between periods and an increase in the proportion of general and administrative expenses capitalized in connection with our increased 2014 development and exploration activities.
Our personnel costs are not expected to increase in 2015 at the pace experienced in recent years given the impact of lower crude oil prices on our 2015 business plans.
G&A expenses in 2013 increased from 2012, primarily due to compensation and benefit cost increases related to the competitive nature of our market and our growing operations, offset partially by decreased professional services costs related to certain projects and initiatives that phased out by the end of 2012. Stock-based compensation expense included in G&A for 2013 was $5.4 million. Our G&A expenses on a Boe basis increased slightly for 2013 compared to 2012 due primarily to these same factors, offset significantly by the increase in overall production volumes between periods.
Other income and expenses
Interest expense. The following table presents interest expense for the periods indicated:
Total interest expense increased from 2013 to 2014 primarily due to increased levels of borrowing on our senior secured revolving credit facility and reduced capitalized interest. Capitalized interest was lower in 2014 compared to 2013 as we ceased capitalizing interest on our CO2 delivery pipelines and facilities upon completing construction of those assets. Total interest expense decreased in 2013 compared to 2012 as our increased levels of borrowing were offset by higher capitalized interest, primarily associated with the construction of CO2 delivery pipelines and facilities.
Loss on extinguishment of debt. On May 2, 2012, we issued $400.0 million aggregate principal amount of 7.625% senior notes maturing on November 15, 2022. Net proceeds from the 7.625% senior notes were used to consummate a tender offer for all of our 8.875% senior notes due 2017, to redeem the 8.875% senior notes not purchased in the tender offer, and for general corporate purposes. During the second quarter of 2012, we recorded a loss of $21.7 million associated with the refinancing of our 8.875% senior notes, including $15.8 million in repurchase or redemption-related fees and a $5.9 million write-off of deferred financing costs and unaccreted discount.
Income taxes
Our federal net operating loss carryforwards were approximately $347 million as of December 31, 2014, which will expire between 2027 and 2034 if unused. As of December 31, 2014, our state net operating loss carryforwards were approximately $386 million, which will expire between 2015 and 2032 if unused. As of December 31, 2014, approximately $262 million of the state net operating loss carryforwards have been reduced by a valuation allowance based on our assessment that it is more likely than not that a portion will not be realized.
Realization of our deferred tax assets is dependent upon generating sufficient future taxable income. Although realization is not assured, we believe it is more likely than not that the deferred tax asset will be realized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near-term if estimates of future taxable income are reduced.
Liquidity and capital resources
We have historically used cash flow from operations, debt financing, and private issuances of common stock as our primary sources of capital. Our primary uses of funds are expenditures for exploration and development, leasehold and property acquisitions, other capital expenditures, and debt service.
Our liquidity is highly dependent on prices we receive for the oil, natural gas and NGLs we produce. Prices received heavily influence our revenue, cash flow, profitability, access to capital and future rate of growth. Prices we receive are determined by prevailing market conditions. Regional and worldwide economic and geopolitical activity, supply versus demand, weather, seasonality and other factors influence market conditions, which often result in significant volatility in commodity prices. Beginning in the fourth quarter of 2014 and continuing into the first quarter of 2015, oil, natural gas and NGL commodity prices declined significantly and will continue to fluctuate in the future. We deal with volatility in commodity prices primarily by maintaining flexibility in our capital investment program with a diversified drilling portfolio and limited long-term commitments, which enables us to respond quickly to industry volatility, as well as aggressively pursuing cost reductions in a market downturn.
We also mitigate the impact of volatility in commodity prices through the usage of derivative instruments which help stabilize our cash flow.
Our debt includes senior notes, which, as of December 31, 2014, is comprised of our 9.875% senior notes due 2020, our 8.25% senior notes due 2021, and our 7.625% senior notes due 2022 (collectively, our “Senior Notes”), in an aggregate principal amount of $1,250 million.
We maintain a senior secured revolving credit facility, which, effective April 1, 2015, will have a borrowing base of $550.0 million, that is collateralized by a substantial portion of our oil and natural gas properties, and, as amended, is scheduled to mature on November 1, 2017. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. We have the capacity to utilize the available funds to supplement our operating cash flows as a financing source for our capital expenditures. If oil and natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural gas properties, the borrowing base may be reduced at future redeterminations, thus reducing funds available under the borrowing base. We mitigate a potential reduction in our borrowing base caused by a decrease in oil and natural gas prices through the use of commodity derivatives.
Sources and uses of cash
Our net (decrease) increase in cash is summarized as follows:
Our operating cash flow is primarily influenced by the prices we receive for our oil, natural gas and NGL production and the quantity we produce. Our cash flows from operating activities are also impacted by changes in working capital.
Cash flows from operating activities were higher in 2014 than they were in 2013 primarily due to the 15% increase in commodity sales driven by an increase in production as well as lower production taxes. These increases were partially offset by higher lease operating and interest charges as well as changes in working capital. Cash flows from operating activities were higher in 2013 than they were in 2012 primarily due to the 16% increase in commodity sales resulting from an increase in production combined with an increase in the average price per Boe. Increased cash flows from commodity sales were partially offset by higher lease operating and general and administrative expenses. Primarily as a result of the above activity, cash flows from operating activities increased by 23% in 2014 from 2013 and increased by 38% in 2013 from 2012.
We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. For the years ended December 31, 2014, 2013, and 2012, cash flows provided by operating activities were approximately 47%, 41%, and 38%, respectively, of cash used for the acquisition and development of our properties. Our capital expenditures for oil and natural gas properties during 2014 are detailed in the next section. During 2014, cash flows used in investing activities included proceeds of $291.4 million primarily from the sale of non-core properties as discussed below in Alternative capital resources. During 2014, we also paid $20.6 million in premiums for put options associated with our crude oil commodity derivatives settling in 2016. During 2013, cash flows used in investing activities included proceeds of $109.7 million from oil and natural gas property dispositions, including approximately $61.4 million from the sale of certain non-strategic properties located in Creek, Love, and Carter counties, Oklahoma, and $17.8 million from the sale of certain non-strategic properties located in Texas County, Oklahoma. During 2012, cash flows used in investing activities included proceeds of $46.0 million from property dispositions, including approximately $37.0 million from the sale of certain mature oil and natural gas properties located in our Velma Area in southern Oklahoma.
We received net derivative settlements totaling $2.4 million, $19.1 million, and $37.3 million during 2014, 2013, and 2012, respectively. Primarily as a result of our capital investments, asset dispositions and derivative settlements, cash flows used in investing activities were $412.2 million, $515.1 million, and $423.2 million during 2014, 2013, and 2012, respectively.
Net cash provided by financing activities was $71.2 million, $269.8 million, and $226.5 million, during 2014, 2013, and 2012, respectively. In 2014, we had proceeds from and repayments of debt of $302.1 million and $228.6 million, respectively, most of which were attributable to our senior secured revolving credit facility. In addition, principal payments under our capital lease obligations, discussed below, were $2.3 million during 2014.
In 2013, we had proceeds from and repayments of debt of $297.8 million and $52.1 million, respectively, most of which were attributable to our senior secured revolving credit facility. A portion of the borrowings from our senior secured revolving credit facility in 2013 were utilized to finance the Cabot Acquisition. We also entered into $24.5 million of capital leases during the year from the sale and subsequent leaseback of existing compressors owned by us.
In 2012, we issued $550.0 million aggregate principal amount of 7.625% senior notes maturing on November 15, 2022 for proceeds of $556.8 million while utilizing a portion of those proceeds to redeem $325.0 million of our 8.875% senior notes and for repayment of borrowings from our senior secured credit facility. Primarily in connection with these transactions, we paid $30.3 million in debt issuance and extinguishment costs and other financing fees. The issuance and retirement of our Senior Notes is described further in “Note 5-Long term debt” in Item 8. Financial Statements and Supplementary Data of this report. During 2012, we also had proceeds from and repayments of debt of $208.6 million and $183.5 million, respectively, most of which were attributable to our senior secured revolving credit facility.
Capital expenditures
Our actual costs incurred, including costs that we have accrued, for 2014 and our budgeted 2015 capital expenditures for oil and natural gas properties are summarized in the following table:
______________
(1)
Includes $49.6 million allocated to our EOR project areas as follows: enhancements of $16.3 million, pipeline and field infrastructure of $8.6 million and CO2 purchases of $24.7 million.
(2)
Budget categories presented include allocations of capitalized interest and general and administrative expenses.
In addition to the capital expenditures for oil and natural gas properties, we spent approximately $11.6 million for property and equipment during 2014.
Our actual costs incurred for 2014 and our budgeted capital expenditures for oil and natural gas properties for 2015 are summarized by area in the following table:
During 2014, we continued our increased focus on the development of our E&P Area assets, which is consistent with our strategy of driving growth through development of our core operations located in the Mid-Continent region. Our oil and natural gas property capital expenditure budget for 2015 is set at $177.3 million, of which $127.7 million, or 72%, is allocated to our E&P Area assets.
We continually evaluate our capital needs and compare them to our capital resources. Our actual expenditures during 2015 may be higher or lower than our budgeted amounts. The 2015 capital budget, based on our expectations of commodity prices and costs, is estimated to fall within the level of cash flows generated from operations. Our level of exploration and development expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows and development results, among other factors. We believe that we will have sufficient funds available through our cash from operations, proceeds from asset divestitures and borrowing capacity under our senior secured revolving credit facility to meet our normal recurring operating needs, debt service obligations, capital requirements and contingencies for the next 12 months.
Indebtedness
Long term debt consists of the following as of the dates indicated:
Please see “Note 5-Long term debt” in Item 8. Financial Statements and Supplementary Data of this report for a discussion of the material terms governing our Senior Notes and senior secured revolving credit facility. For information on the future maturities of our long term debt, see the table below under “Contractual obligations.”
Senior secured revolving credit facility
We maintain a senior secured revolving credit facility, which is collateralized by our oil and natural gas properties, and matures on November 1, 2017. As of March 31, 2015, we have $450.0 million of outstanding borrowings under our senior secured revolving credit facility.
Availability under our senior secured revolving credit facility is subject to a borrowing base which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once between each scheduled redetermination and in the event of early termination of our derivative contracts. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. If oil and natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural gas properties, the borrowing base may be reduced, thus reducing funds available under the borrowing base.
If the outstanding borrowings under our senior secured revolving credit facility were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess. Within ten days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay a portion of our bank borrowings in the amount of the excess either in a lump sum within thirty days or in equal monthly installments over a six-month period, (2) to submit within thirty days additional oil and natural gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and natural gas properties within thirty days.
We began 2014 with an initial borrowing base under our senior secured revolving credit facility of $600.0 million. On May 19, 2014, we entered into a Limited Consent and Fourteenth Amendment to our senior secured revolving credit facility which imposed a series of automatic borrowing base reductions as the divestitures of our oil and natural gas properties were completed (see “Note 3-Acquisitions and divestitures”). As a result of two divestitures that closed during the second quarter and two additional divestitures that closed during the third quarter, our borrowing base was reduced to $484.5 million effective July 18, 2014. Our semiannual redetermination, effective November 5, 2014, increased our borrowing base to $650.0 million. Our lenders have completed the semi-annual borrowing base redetermination originally scheduled for May 1, 2015, which has resulted in a decrease of our borrowing base to $550.0 million to be effective on April 1, 2015. The decrease was primarily associated with reduced oil and gas pricing used to determine the value of our reserves.
Our senior secured revolving credit facility requires us to maintain a current ratio, as defined in our senior secured revolving credit facility, of not less than 1.0 to 1.0. The definition of current assets and current liabilities used for determination of the current ratio computed for loan compliance purposes differs from current assets and current liabilities determined in compliance with GAAP. Since compliance with financial covenants is a material requirement under our senior secured revolving credit facility, we consider the current ratio calculated under our senior secured revolving credit facility to be a useful measure of our liquidity because it includes the funds available to us under our senior secured revolving credit facility and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. At December 31, 2014 and 2013, our current ratio as computed using GAAP was 1.04 and 0.80, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 1.79 and 2.35, respectively. The following table reconciles our current assets and current liabilities using GAAP to the same items for purposes of calculating the current ratio for our loan compliance:
Our senior secured revolving credit facility, as amended, requires us to maintain a Consolidated Net Debt to Consolidated EBITDAX ratio, as defined in our senior secured revolving credit facility, of not greater than 4.50 to 1.0 for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter. As of December 31, 2014, the availability under our senior secured revolving credit facility was $302.1 million, which was not limited by the Consolidated Net Debt to Consolidated EBITDAX covenant.
We have negotiated an amendment to our senior secured revolving credit facility (the “Fifteenth Amendment”) to be effective April 1, 2015. Among other things, the amendment will replace the Consolidated Net Debt to Consolidated EBITDAX covenant described above with a covenant based on the ratio of Consolidated Net Secured Debt to Consolidated EBITDAX, as defined in the amendment. Under this covenant, we are required to maintain a ratio of Consolidated Net Secured Debt to Consolidated EBITDAX no greater than 2.25 to 1.0 for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter. For the same applicable periods, the Fifteenth Amendment also requires us to maintain an Interest Coverage Ratio, as defined in the amendment, of no less than 2.00 to 1.00. The amendment revises the definition of Consolidated EBITDAX to exclude up to $25.0 million in expenses incurred subsequent to January 1, 2015, in connection with our cost savings initiatives, transition, business optimization and other restructuring charges. The charges we have incurred to date under this category are described above under “Business and Industry Outlook.” Under the Fifteenth Amendment, we are also allowed to incur an additional $300.0 million in Additional Permitted Debt, as defined in the amendment to now include both secured and unsecured debt.
Capital leases
During 2013, we entered into lease financing agreements with U.S. Bank National Association for $24.5 million through the sale and subsequent leaseback of existing compressors owned by us. The lease financing obligations are for 84-month terms and include the option to purchase the equipment for a specified price at 72 months as well as an option to purchase the equipment at the end of the lease term for its then-current fair market value. Lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.8%. Minimum lease payments are $3.2 million annually.
Alternative capital resources
We have historically used cash flow from operations, debt financing, and private issuances of common stock as our primary sources of capital. During 2014, a significant source of liquidity was derived from asset dispositions. In late 2013, our Board approved selling our Ark-La-Tex, Permian Basin, Gulf Coast, and North Texas properties in five property packages to implement our strategy of focusing our operations in the Mid-Continent area. The five packages include: (i) our Fort Worth Basin package located in North Texas; (ii) our Delaware Basin package; (iii) our Central Basin Platform package; (iv) our Ark-La-Tex package; and (v) our Gulf Coast package.
During the second quarter of 2014, we closed on the sales of two of the five property packages in our divestiture plan. In May 2014, we sold our Fort Worth Basin package to Scout Energy Group I, LP, for cash proceeds of $23.7 million and we sold our Delaware Basin package to RKI Exploration & Production, LLC for cash proceeds of $124.7 million. During the third quarter of 2014, we closed on the sales of two additional property packages. Our Ark-La-Tex and Central Basin Platform property packages, both of which were sold to RAM Energy, LLC (“RAM”), closed in July 2014 for total proceeds of $95.9 million. These proceeds are net of post-closing adjustments.
In addition to the packages discussed above, we closed various other divestitures during the year ended December 31, 2014. These divestitures resulted in cash proceeds of $20.0 million from the sale of leasehold interests in the Eagle Ford Formation in Texas and $24.5 million from the sale of various other properties predominantly located in Andrews County, Texas, which comprised part of our Permian Basin properties, and Osage County, Oklahoma.
Proceeds from the property sales discussed above provide, and proceeds from any future divestitures will provide, us with an additional source of liquidity to pay down borrowings under our senior secured revolving credit facility, fund capital expenditures and for general corporate purposes. In the future, our sources of liquidity may include asset sales, additional public or private issuances of common or preferred stock, or project financing. While we believe we would be able to obtain funds through one or more of these alternative sources, if needed, we cannot provide assurance that these resources would be available on terms acceptable to us.
Contractual obligations
The following table summarizes our contractual obligations and commitments as of December 31, 2014:
We have a long-term contract with renewal options to purchase CO2 manufactured at the Arkalon ethanol plant near Liberal, Kansas. Pricing is fixed for the contract term which expires in May 2024. During 2014, we purchased approximately 13 MMcf/d of CO2 under this contract, and we expect to purchase an average of approximately 13 MMcf/d over the remainder of the contract term. Purchases under this contract were $1.3 million, $1.3 million, and $1.1 million during 2014, 2013, and 2012, respectively.
We have rights under three additional contracts with fertilizer plants under which we purchase CO2 that is restricted, in whole or in part, for use only in EOR projects. The fertilizer plants retain the right to install additional equipment and use some of the CO2 to make certain fertilizer products, which could reduce the CO2 available to us. The first of these contracts,with the plant in Enid, Oklahoma, is scheduled to expire in 2016 and we expect to purchase 2 MMcf/d of CO2 through 2015, subject to availability. During 2014, we purchased approximately 3 MMcf/d of CO2 under this contract. Total purchases, which include transportation charges, during 2014, 2013, and 2012 were $1.1 million, $0.6 million, and $1.2 million, respectively. We may terminate or permanently reduce our purchase rate under this contract at the end of any calendar year with 13 months’ notice. The second contract, with the plant in Borger, Texas, expires in February 2021. During 2014, we were purchasing an average of approximately 14 MMcf/d and expect our purchases to continue at that level for 2015 then decrease to 11 MMcf/d for the remaining contract term. Purchases under this contract were $1.1 million, $1.3 million, and $1.5 million during 2014, 2013, and 2012, respectively. Pricing under both of these contracts is dependent on certain variable factors, including the price of oil. Our third contract, with the plant in Coffeyville, Kansas, expires in 2033 but provides the option for renewal. Pricing under the contract is fixed for the first five contract years and variable thereafter. We are obligated to purchase 35 MMcf/d for the remaining contract years or pay for any deficiencies at the price in effect when the minimum delivery was to have occurred. After the first ten contract years, we may permanently reduce up to 100% of our purchase rate under this contract with six months’ notice. During 2014, we purchased 38 MMcf/d and expect our purchases to average approximately 42 MMcf/d over the remainder of the contract term. Purchases under this contract totaled $1.4 million during 2014.
We rent equipment used on our oil and natural gas properties and have operating lease agreements for office equipment. Rent expense for the years ended December 31, 2014, 2013, and 2012 was $11.1 million, $9.0 million, and $8.1 million, respectively. Our leases relating to office equipment have terms of up to five years. In June 2014, we entered into two non-cancelable operating leases for CO2 recycle compressors at our EOR facilities which expire in 2021. Amounts related to our operating lease obligations are disclosed in the table above.
Other commitments that are not currently recorded on our consolidated balance sheets relate to contracts in place as of December 31, 2014, primarily for the purchase of pipe and other equipment relating to our CO2 projects, drilling rig services, and other assets. These purchases are generally expected to be finalized within the next several months and are included in our capital expenditures budget for 2015. We generally have the ability to terminate the contracts for purchase of equipment and other assets, in which case our liability would be limited to the cost incurred by the vendor up to that point. Because we do not currently anticipate canceling these contracts, the estimated payments under these contracts have been included in “Other commitments” above.
Critical accounting policies
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements. The preparation of these statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. We base our estimates on historical experience and other sources that we believe are reasonable at the time. Actual results may differ from the estimates and assumptions we used in preparation of our financial statements. We evaluate our estimates and assumptions on a regular basis. Described below are the most significant policies and the related estimates and assumptions we apply in the preparation of our financial statements. See “Note 1-Nature of operations and summary of significant accounting policies” in Item 8. Financial Statements and Supplementary Data in this report for an additional discussion of accounting policies and estimates made by management.
Revenue recognition. We derive almost all of our revenue from the sale of crude oil and natural gas produced from our oil and natural gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and actual payment received for all prior months are recorded in the month payment is received.
Derivative instruments. We determine the fair value of our crude oil, natural gas, and basis swaps by reference to forward pricing curves for oil and natural gas futures contracts. The difference between the forward price curve and the contractual fixed price is discounted to the measurement date using a credit risk adjusted discount rate. We have determined that the fair value methodology described above for the remainder of our swaps is consistent with observable market inputs and have categorized them as Level 2. We determine fair value for our crude oil collars, enhanced swaps, and purchased and sold puts using an option pricing model which takes into account market volatility, market prices, contract parameters, and credit risk. Due to unavailability of observable volatility data input for these instruments, we have determined that their fair value measurements are categorized as Level 3. Derivative instruments are discounted using a rate that incorporates our nonperformance risk for derivative liabilities, and our counterparties’ credit risk for derivative assets. Our derivative contracts have been executed with the institutions that are parties to our revolving credit facility. We believe the credit risks associated with all of these institutions are acceptable.
Since we have elected to not designate any of our derivative contracts as hedges since 2010, we mark our contracts to their period end market values and the change in the fair value of the contracts is included in the “Non-hedge derivative gains (losses)” line in our consolidated statements of operations. As a result, our reported earnings could include large non-cash fluctuations, particularly in volatile pricing environments.
Oil and natural gas properties.
•
Full cost accounting. We use the full cost method of accounting for our oil and natural gas properties. Under this method, all costs incurred in the exploration and development of oil and natural gas properties are capitalized into a cost center. These costs include drilling and equipping productive wells, dry hole costs, seismic costs and delay rentals. Capitalized costs also include salaries, employee benefits, consulting services and other expenses that directly relate to our exploration and development activities.
•
Proved oil and natural gas reserves quantities. Proved oil and natural gas reserves are the quantities of crude oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. The estimates of proven reserves for a given reservoir may change significantly over time as a result of changing prices, operating cost, additional development activity and the actual operating performance.
Our proved reserve information included in this report is based on estimates prepared by Cawley, Gillespie & Associates, Inc. and Ryder Scott Company, L.P. each independent petroleum engineers, and our engineering staff. The independent petroleum engineers evaluated approximately 89% of the estimated future net revenues of our proved reserves discounted at 10% as of December 31, 2014. We continually make revisions to reserve estimates throughout the year as additional information becomes available.
•
Depreciation, depletion and amortization. The quantities of proved oil and natural gas reserves are a significant component of our calculation of depreciation, depletion and amortization expense, and revisions in such estimates may alter the rate of future expense. The depreciation, depletion and amortization rate is determined using the units-of-production method based on estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based on the relative energy content.
•
Full cost ceiling limitation. Under the full cost method, the net capitalized costs of oil and natural gas properties recorded on our consolidated balance sheets cannot exceed the estimated future net revenues discounted at 10% plus the cost of unproved properties not being amortized. The ceiling calculation requires that prices and costs used to determine the estimated future net revenues exclude escalations based upon future conditions. If commodity prices remain at their current depressed levels, the average prices used in the ceiling calculation will decline and will likely cause potential write-downs of our oil and natural gas properties. Furthermore, if we have downward revisions to our estimated reserve quantities, it is possible that write-downs could occur in the future as well.
•
Costs not subject to amortization. Costs of unevaluated properties are excluded from our amortization base until we have evaluated the properties. The costs associated with unevaluated leasehold acreage and seismic data, exploratory wells currently drilling, and capitalized interest are initially excluded from our amortization base. Leasehold costs are either transferred to the amortization base with the costs of drilling a well or are assessed quarterly for possible impairment. Our future depreciation, depletion and amortization rate would increase if costs are transferred to the amortization base without any associated reserves.
•
Future development and abandonment costs. Our future development costs include costs to be incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to plug and abandon our oil and natural gas properties and related facilities. We develop estimates of these costs for each of our properties based on their location, type of facility, market demand for equipment and currently available procedures. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make numerous judgments. These judgments are subject to future revisions from changing technology and regulatory requirements. We review our assumptions and estimates of future development and future abandonment costs on a quarterly basis.
We record a liability for the estimated fair value of an asset retirement obligation in the period in which it is incurred and the corresponding cost is capitalized by increasing the carrying value of the related asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset.
We use the present value of estimated cash flows related to our asset retirement obligation to determine the fair value. Significant assumptions used in estimating such obligations include estimates of the ultimate costs of dismantling and site restoration, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments, all of which are Level 3 inputs in the fair value hierarchy. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment will be required for the related asset. We believe the estimates and judgments reflected in our financial statements are reasonable but are necessarily subject to the uncertainties we have just described. Accordingly, any significant variance in any of the above assumptions or factors could materially affect our estimated future cash flows.
Income taxes. Deferred income taxes are provided for the difference between the tax basis of assets and liabilities and the carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled. Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities. We record adjustments to actual in the period we file our tax returns.
Valuation allowance for NOL carryforwards. In computing our income tax expense, we assess the need for a valuation allowance on deferred tax assets, which consist primarily of net operating loss, or NOL, carryforwards. For federal income tax purposes these NOL carryforwards expire 15 to 20 years from the year of origination. We generally assess our ability to fully utilize these carryforwards by estimating expected future taxable income based on the assumption that we will produce our existing reserves, as scheduled for production in our reserve report and by analyzing the expected reversal of existing deferred tax liabilities. These computations are imprecise due to the extensive use of estimates and assumptions. Each quarter we assess our ability to utilize NOL carryforwards. We record a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such asset will not be realized.
Impairment of long-lived assets. Impairment losses are recorded on property and equipment used in operations and other long-lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amounts. Impairment is measured based on the excess of the carrying amount over the fair value of the asset.
Recent accounting pronouncements
See “Note 1-Nature of operations and summary of significant accounting policies” in Item 8. Financial Statements and Supplementary Data of this report for a discussion of recently adopted and issued accounting standards. Additionally, we are monitoring the joint standard-setting efforts of the Financial Accounting Standards Board and International Accounting Standards Board. There are a number of pending accounting standards being targeted for completion in 2015 and beyond, including, but not limited to, standards relating to accounting for leases, fair value measurements, and financial instruments. Because these pending standards have not yet been finalized, at this time we are not able to determine the potential future impact these standards will have, if any, on our financial position, results of operations or cash flows.
Effects of inflation and pricing
While the general level of inflation affects certain of our costs, factors unique to the oil and natural gas industry result in independent price fluctuations. Historically, significant fluctuations have occurred in oil and natural gas prices. In addition, changing prices often cause costs of equipment and supplies to vary as industry activity levels increase and decrease to reflect perceptions of future price levels. Although it is difficult to estimate future prices of oil and natural gas, price fluctuations have had, and will continue to have, a material effect on us.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity prices. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. We cannot predict future oil and natural gas prices with any degree of certainty. Sustained declines in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and natural gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce our borrowing base under our senior secured revolving credit facility and adversely affect our liquidity and our ability to obtain capital for our acquisition, exploration, and development activities. Based on our production for the year ended December 31, 2014, our gross revenues from commodity sales would change approximately $7.5 million for each $1.00 change in oil and NGL prices and $2.1 million for each $0.10 change in natural gas prices.
To mitigate a portion of our exposure to fluctuations in commodity prices, we enter into various types of derivative instruments, including commodity price swaps, costless collars, put options, and basis protection swaps. We do not apply hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as non-hedge derivative gains (losses) in the consolidated statements of operations. This can have a significant impact on our results of operations due to the volatility of the underlying commodity prices. Please see “Note 13-Commitments and contingencies” in Item 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of independent registered public accounting firm
Board of Directors
Chaparral Energy, Inc.
We have audited the accompanying consolidated balance sheets of Chaparral Energy, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2014 and 2013, 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, 2014. 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. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Chaparral Energy, Inc. and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America.
Chaparral Energy, Inc. and subsidiaries
Consolidated balance sheets
The accompanying notes are an integral part of these consolidated financial statements.
Chaparral Energy, Inc. and subsidiaries
Consolidated statements of operations
The accompanying notes are an integral part of these consolidated financial statements.
Chaparral Energy, Inc. and subsidiaries
Consolidated statements of comprehensive income
The accompanying notes are an integral part of these consolidated financial statements.
Chaparral Energy, Inc. and subsidiaries
Consolidated statements of stockholders’ equity
The accompanying notes are an integral part of these consolidated financial statements.
Chaparral Energy, Inc. and subsidiaries
Consolidated statements of cash flows
The accompanying notes are an integral part of these consolidated financial statements.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Note 1: Nature of operations and summary of significant accounting policies
Chaparral Energy, Inc. and its subsidiaries, (collectively, “we”, “our”, “us”, or the “Company”) are involved in the acquisition, exploration, development, production and operation of oil and natural gas properties. Properties are located primarily in Oklahoma and Texas.
A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows.
Principles of consolidation
The consolidated financial statements include the accounts of Chaparral Energy, Inc. and its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated.
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“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.
The more significant areas requiring use of assumptions, judgments and estimates on our consolidated financial statements include: quantities of proved oil and natural gas reserves; cash flow estimates used in impairment tests of other long-lived assets; depreciation, depletion and amortization; asset retirement obligations; estimates of our stock-based compensation awards, assigning fair value and allocating purchase price in connection with business combinations; valuation allowances associated with deferred income taxes; valuation of derivative instruments; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could significantly differ from these estimates.
Reclassifications
Certain reclassifications have been made to prior period financial statements to conform to current period presentation. The reclassifications had no effect on our previously reported results of operations.
Cash and cash equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. As of December 31, 2014, cash with a recorded balance totaling $27,802 was held at JP Morgan Chase Bank, N.A. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts.
Accounts receivable
We have receivables from joint interest owners and oil and natural gas purchasers which are generally uncollateralized. We generally review our oil and natural gas purchasers for credit worthiness and general financial condition. We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties of which we are the operator. Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts. Accounts receivable are generally due within 30 days and accounts outstanding longer than 60 days are considered past due. We establish our allowance for doubtful accounts by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties we operate, and the owner’s ability to pay its obligation, among other things.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
We write off accounts receivable when they are determined to be uncollectible. Recovered amounts previously written off are offset against the allowance and reduce expense in the year of recovery. Accounts receivable consisted of the following at December 31:
Inventories
Inventories are comprised of equipment used in developing oil and natural gas properties and oil and natural gas product inventories. Equipment inventory is carried at the lower of cost or market using the average cost method. Oil and natural gas product inventories are stated at the lower of production cost or market. Inventories are shown net of a provision for obsolescence, commensurate with known or estimated exposure, which is reflected in the valuation allowance disclosed below. Inventories consisted of the following at December 31:
Property and equipment
Property and equipment is capitalized and stated at cost, while maintenance and repairs are expensed currently.
Depreciation and amortization are provided in amounts sufficient to relate the cost of depreciable assets to operations over their estimated service lives using the straight-line method. Estimated useful lives of our assets are as follows:
Oil and natural gas properties
Capitalized Costs. We use the full cost method of accounting for oil and natural gas properties and activities. Accordingly, we capitalize all costs incurred in connection with the exploration for and development of oil and natural gas reserves. Proceeds from the disposition of oil and natural gas properties are accounted for as a reduction in capitalized costs, with no gain or loss generally recognized unless such dispositions involve a significant alteration in the depletion rate. We capitalize internal costs that can be directly identified with exploration and development activities, but do not include any costs related to production, general corporate overhead or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and natural gas wells, including salaries, benefits, capitalized interest on qualified projects and other internal costs directly attributable to these activities.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
The costs of unevaluated oil and natural gas properties are excluded from amortization until the properties are evaluated. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Work in progress costs are included in unevaluated oil and natural gas properties and as of December 31, 2014, include $190,356 of capital costs incurred for undeveloped acreage, $72,046 for the construction of CO2 delivery pipelines and facilities for which there are no reserves, and $26,023 for wells and facilities in progress pending determination. As of December 31, 2013, work in progress costs included $196,227 of capital costs incurred for undeveloped acreage, $115,828 for the construction of CO2 delivery pipelines and facilities for which there are no reserves, and $9,422 for wells and facilities in progress pending determination.
Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties are provided using the units-of-production method based on estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. Our cost basis for depletion includes estimated future development costs to be incurred on proved undeveloped properties. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs, and the anticipated proceeds from salvaging equipment.
Ceiling Test. In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related estimated future net revenues discounted at 10% (“PV-10 value”), net of tax considerations, plus the cost of unproved properties not being amortized.
Our estimates of oil and natural gas reserves as of December 31, 2014, 2013, and 2012 were prepared using an average price for oil and natural gas based upon the first day of each month for the prior twelve months as required by the Securities Exchange Commission (“SEC”). As of December 31, 2014, the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties, and no ceiling test impairment was recorded.
A decline in oil and natural gas prices subsequent to December 31, 2014 could result in ceiling test write-downs in future periods. Due to the substantial decline of commodity prices during the third and fourth quarters of 2014, which have remained low during the first quarter of 2015, we anticipate that we will have a ceiling test write-down during 2015. The amount of any future impairment is difficult to predict, and will depend on the average oil and natural gas prices during each period, the incremental proved reserves added during each period, and additional capital spent.
Impairment of long-lived assets
Impairment losses are recorded on property and equipment used in operations and other long-lived assets held and used when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. Impairment losses are also recorded on assets classified as held for sale when there is an excess of carrying value over fair value less costs to sell.
We recorded impairment losses of $3,490 and $1,500 related to certain of our drilling rigs during the years ended December 31, 2013 and 2012, respectively. The drilling rigs were previously classified as held for sale but were reclassified to property and equipment in late 2013 when the ultimate disposal became uncertain. Additionally, we recognized $500 of impairment losses during 2012 related primarily to drill pipe held and used. Our impairment losses are reflected as loss on impairment of other assets in the consolidated statements of operations.
Deferred income taxes
Deferred income taxes are provided for significant carryforwards and temporary differences between the tax basis of an asset or liability and its reported amount in the financial statements that will result in taxable or deductible amounts in future years. Deferred income tax assets or liabilities are determined by applying the presently enacted tax rates and laws. We record a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such assets will not be realized.
If applicable, we would report a liability for tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return, and would recognize interest and penalties related to uncertain tax positions in interest expense. As of December 31, 2014 and 2013, we have not recorded a liability or accrued interest or penalties related to uncertain tax positions.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Tax years beginning with 2011 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.
Derivative transactions
We use derivative instruments to reduce the effect of fluctuations in crude oil and natural gas prices, and we recognize all derivatives as either assets or liabilities measured at fair value. Changes in the fair value of derivatives that are not accounted for as hedges are reported immediately in non-hedge derivative gains (losses) in the consolidated statements of operations. Cash flows associated with non-hedge derivatives are reported as investing activities in the consolidated statements of cash flows unless the derivatives contain a significant financing element, in which case they are reported as financing activities.
Effective April 1, 2010, we elected to discontinue hedge accounting prospectively. The effective portion of changes in the fair value of derivatives qualifying and designated as cash flow hedges was recognized in accumulated other comprehensive income (loss) (“AOCI”) prior to April 1, 2010, and is reclassified into income as the hedged transactions occur. As of December 31, 2013, all amounts related to de-designated cash flow hedges have been reclassified into earnings.
We offset assets and liabilities for derivative contracts executed with the same counterparty under a master netting arrangement. See “Note 6-Derivative instruments” for additional information regarding our derivative transactions.
Fair value measurements
Fair value is defined by the Financial Accounting Standards Board (“FASB”) 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. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.
Assets and liabilities recorded at fair value in the consolidated balance sheets are categorized according to the fair value hierarchy defined by the FASB. The hierarchical levels are based upon the level of judgment associated with the inputs used to measure the fair value of the assets and liabilities. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the asset or liability is categorized based on the lowest level input that is significant to the fair value measurement in its entirety. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.
Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2 inputs include adjusted quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities included in this category are derivatives with fair values based on published forward commodity price curves and other observable inputs. Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Assets carried at fair value and included in this category are certain financial derivatives, additions to our asset retirement obligations, and valuation of assets and liabilities acquired in our Cabot Acquisition. See “Note 7-Fair value measurements” for additional information regarding our fair value measurements.
Valuation of business combinations
In connection with a purchase business combination, the acquiring company must record assets acquired and liabilities assumed based on fair values as of the acquisition date. We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions are related to the estimated fair values assigned to proved and unproved oil and natural gas properties. To estimate the fair values of these properties, we utilize estimates of oil and natural gas reserves. We make future price assumptions to apply to the estimated reserves quantities acquired and estimate future operating and development costs to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows were discounted using market-based weighted average cost of capital rates determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rates are subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net cash flows of the unproved reserves were reduced by additional risk-weighting.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Asset retirement obligations
We own oil and natural gas properties that require expenditures to plug, abandon or remediate wells at the end of their productive lives and to remove tangible equipment and facilities at the end of oil and natural gas production operations in accordance with applicable federal and state laws. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of oil and natural gas properties. The accretion of the asset retirement obligations is included in depreciation, depletion and amortization on the consolidated statements of operations. In certain instances, we are required to make deposits to escrow accounts for plugging and abandonment obligations. See “Note 8-Asset retirement obligations” for additional information regarding our asset retirement obligations.
Environmental liabilities
We are subject to extensive federal, state and local environmental laws and regulations covering discharge of materials into the environment. Because these laws and regulations change regularly, we are unable to predict the conditions and other factors over which we do not exercise control that may give rise to environmental liabilities affecting us. Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of December 31, 2014 and 2013, we have not accrued for or been fined or cited for any environmental violations which would have a material adverse effect upon our financial position, operating results, or cash flows.
Revenue recognition
Sales of oil, natural gas and NGLs are recorded when title of oil, natural gas and NGL production passes to the customer. Well supervision fees and overhead reimbursements from producing properties are recognized as expense reimbursements from outside interest owners when the services are performed. Sales of products are recognized at the time of delivery of materials.
Gas balancing
In certain instances, the owners of the natural gas produced from a well will select different purchasers for their respective ownership interest in the wells. If one purchaser takes more than its rateable portion of the natural gas, the owners selling to that purchaser will be required to satisfy the imbalance in the future by cash payments or by allowing the other owners to sell more than their share of production. We recognize gas imbalances on the sales method and, accordingly, have recognized revenue on all production delivered to our purchasers. To the extent future reserves exist to enable the other owners to sell more than their rateable share of gas, no liability is recorded for our obligation for natural gas taken by our purchasers which exceeds our ownership interest of the well’s total production. As of December 31, 2014 and 2013, our aggregate imbalance due to under production was approximately 2,005 MMcf and 2,449 MMcf, respectively. As of December 31, 2014 and 2013, our aggregate imbalance due to over production was approximately 1,276 MMcf and 1,553 MMcf, respectively, and a liability for gas imbalances of $1,110 and $1,588, respectively, was included in accounts payable and accrued liabilities.
Stock-based compensation
Our stock-based compensation programs consist of phantom stock, restricted stock units (“RSU”), and restricted stock awards issued to employees. Generally, we use new shares to grant restricted stock awards, and we cancel restricted shares forfeited or repurchased for tax withholding. Canceled shares are available to be issued as new grants under our 2010 Equity Incentive Plan.
The estimated fair value of the phantom stock and RSU awards are remeasured at the end of each reporting period until settlement. The estimated fair market value of these awards is calculated based on our total asset value less total liabilities, with both assets and liabilities being adjusted to fair value in accordance with the terms of the Phantom Stock Plan and the Non-Officer Restricted Stock Unit Plan. The primary adjustment required is the adjustment of oil and natural gas properties from net book value to the discounted and risk-adjusted reserve value based on internal reserve reports priced on NYMEX forward strips. Compensation cost associated with the phantom stock awards and RSU awards is recognized over the vesting period using the straight-line method and the accelerated method, respectively.
The fair value of our restricted stock awards that include a service condition is based upon the estimated fair market value of our common equity per share on a minority, non-marketable basis on the date of grant, and is remeasured at the end of each reporting period until settlement. We recognize compensation cost over the requisite service period using the accelerated method for awards with graded vesting.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
We use a Monte Carlo model to estimate the grant date fair value of restricted stock awards that include a market condition. This model includes various significant assumptions, including the expected volatility of the share awards and the probabilities of certain vesting conditions. Compensation cost associated with restricted stock awards that include a market condition is recognized over the requisite service period using the straight-line method.
The assumptions used to value our stock-based compensation awards reflect our best estimates, but they involve inherent uncertainties based on market conditions generally outside of our control. As a result, if other assumptions had been used, stock-based compensation expense could have been significantly impacted.
The costs associated with our stock-based compensation programs is calculated net of forfeitures, which are estimated based on our historical and expected turnover rates. If our actual forfeiture rate is materially different from our estimate, the stock-based compensation cost could be different from what we have recorded in the current period.
See “Note 10-Stock-based compensation” for additional information relating to stock-based compensation.
Recently adopted accounting pronouncements
Other Expenses. In July 2011, the FASB issued authoritative guidance regarding how health insurers should recognize and classify in their income statements the fees mandated by the Health Care and Education Reconciliation Act (“HCERA”). The HCERA imposes an annual fee upon health insurers for each calendar year beginning on or after January 1, 2014. The annual fee will be allocated to individual entities providing health insurance to employees based on a ratio, as provided for in the HCERA, and is not tax deductible. This guidance specifies that once the entity has provided qualifying health insurance in the calendar year in which the fee is payable, the liability for the entity’s fee should be estimated and recorded in full with a corresponding deferred cost that is amortized to expense on a straight line basis, unless another method better allocates the fee over the calendar year that it is payable. This guidance, which was effective and adopted by us in the first quarter of 2014, did not have a material impact on our financial statements and results of operations.
Recently issued accounting pronouncements
In May 2014, the FASB issued authoritative guidance that supersedes previous revenue recognition requirements and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This guidance is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. The standard permits the use of either the retrospective or cumulative effect transition method. Early adoption is not permitted. We are currently evaluating the effect the new standard will have on our financial statements and results of operations.
In August 2014, the FASB issued authoritative guidance that requires entities to evaluate whether there is substantial doubt about their ability to continue as a going concern and requires additional disclosures if certain criteria are met. This guidance is effective for fiscal periods after December 15, 2016 and interim periods thereafter. We do not expect this guidance to materially impact our financial statements or results of operations.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Note 2: Supplemental disclosures to the consolidated statements of cash flows
Supplemental disclosures to the consolidated statements of cash flows are presented below:
Note 3: Acquisitions and divestitures
2014 Divestitures
During 2014, we closed on the sales of four of the five property packages that comprise our plan to divest our assets in Ark-La-Tex, Permian Basin, Gulf Coast, and North Texas. The five packages include: (i) our Fort Worth Basin package located in North Texas; (ii) our Delaware Basin package; (iii) our Central Basin Platform package; (iv) our Ark-La-Tex package; and (v) our Gulf Coast package. In May 2014, we sold our Fort Worth Basin package to Scout Energy Group I, LP, for cash proceeds of $23,702 and we sold our Delaware Basin package to RKI Exploration & Production, LLC for cash proceeds of $124,717. In July 2014, we sold our Ark-La-Tex and Central Basin Platform property packages to RAM Energy, LLC (“RAM”) for cash proceeds of $49,078 and $46,830, respectively. Proceeds from these property packages are net of post-closing adjustments. As these properties did not represent a material portion of our oil and natural gas reserves, individually or in the aggregate, we did not record any gain or loss on the sales and instead, reduced our full cost pool by the amount of the net proceeds without significant alteration to our depletion rate.
In addition to the packages discussed above, we had various other divestitures during the year ended December 31, 2014. These divestitures resulted in cash proceeds of $20,007 from the sale of leasehold interests in the Eagle Ford Formation in Texas and $24,478 from the sale of various other properties predominantly located in Andrews County, Texas, which comprised part of our Permian Basin properties, and Osage County, Oklahoma.
2013 Acquisition and divestitures
Cabot Acquisition. In late 2013, we acquired additional oil and natural gas properties consisting of approximately 131,000 (66,000 net) acres in the Panhandle Marmaton play from Cabot Oil & Gas Corporation for approximately $153,858, net of pre-closing purchase price adjustments and subject to post closing adjustments (the “Cabot Acquisition”). The Cabot Acquisition expanded our presence in the Panhandle Marmaton play, adding oil and natural gas reserves and production to our existing asset base in this area.
Our acquisition qualified as a business combination for accounting purposes and, as such, we estimated the fair value of the acquired properties as of the December 18, 2013 acquisition date, which was the date on which we obtained control of the properties. The fair value of the assets and liabilities acquired was estimated using assumptions that represent Level 3 inputs. See “Note 7-Fair value measurements” for additional discussion of the measurement inputs.
We estimated the consideration paid for these properties approximated the fair value that would be paid by a typical market participant. As a result, no goodwill or bargain purchase gain was recognized in conjunction with the purchase. Acquisition-related costs of $951 have been expensed as incurred in general and administrative expense in the accompanying consolidated statements of operations for the year ended December 31, 2013.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
The following table summarizes the consideration paid to acquire the properties and the amounts of the assets acquired and liabilities assumed as of December 18, 2013.
The following unaudited pro forma combined results of operations for the years ended December 31, 2013 and 2012 are presented as though we completed the Cabot Acquisition as of January 1, 2012. The pro forma combined results of operations for the years ended December 31, 2013 and 2012 have been prepared by adjusting the historical results of the acquired properties and estimates of the effect of the transaction on the combined results. These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved had the transaction been in effect for the periods presented or that may be achieved by us in the future. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. The pro forma information below includes adjustments for depletion, depreciation, amortization and accretion expense, interest expense, acquisition costs, and related income tax effects.
Divestitures. During 2013, we sold various oil and natural gas properties for total cash proceeds of approximately $109,710. These included properties in Creek, Love and Carter counties, Oklahoma, that were sold for approximately $61,440 and properties in Texas County, Oklahoma, that were sold for approximately $17,800. In accordance with the full cost method of accounting, we reduced our full cost pool by the amount of the net proceeds and did not record a gain or loss on the sale.
2012 Acquisition and divestitures
On May 30, 2012, we sold certain mature oil and natural gas properties located in our Velma Area in southern Oklahoma for a cash price of $37,000 subject to post-closing adjustments. In accordance with the full cost method of accounting, we reduced our full cost pool by the amount of the net proceeds and did not record a gain or loss on the sale.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Note 4: Property and equipment
Major classes of property and equipment consist of the following at December 31:
Property and equipment leased under capital leases, which are included in the above amounts, consist of the following at December 31:
Note 5: Long-term debt
As of the dates indicated, long-term debt consists of the following:
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Maturities of long-term debt and capital leases, excluding premiums or discounts on our senior notes, are as follows as of December 31, 2014:
Senior Notes
The senior notes, which, as of December 31, 2014, include our 9.875% senior notes due 2020, our 8.25% senior notes due 2021, and our 7.625% senior notes due 2022 (collectively, our “Senior Notes”) are our senior unsecured obligations, rank equally in right of payment with all of our existing and future senior debt, and rank senior to all of our existing and future subordinated debt. The Senior Notes are redeemable, in whole or in part, prior to their maturity at redemption prices specified in the indentures, plus accrued and unpaid interest to the date of redemption.
Interest on the Senior Notes is payable semi-annually, and the principal is due upon maturity. Certain of the Senior Notes were issued at a discount or a premium which is amortized to interest expense over the term of the respective series of Senior Notes. Net amortization of the (premium) discount was $(268), $(387), and $439 during the years ended December 2014, 2013 and 2012, respectively.
We and our restricted subsidiaries are subject to certain negative and financial covenants under the indentures governing the Senior Notes. The provisions of the indentures limit our and our restricted subsidiaries’ ability to, among other things:
•
incur or guarantee additional debt and issue certain types of preferred stock;
•
pay dividends on capital stock or redeem, repurchase, or retire capital stock or subordinated debt;
•
make investments;
•
incur liens on assets;
•
create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to us;
•
engage in transactions with affiliates;
•
sell assets, including capital stock of our subsidiaries;
•
consolidate, merge or transfer assets; and
•
enter into other lines of business.
If we experience a change of control (as defined in the indentures governing the Senior Notes), including making certain asset sales, subject to certain conditions, we must give holders of the Senior Notes the opportunity to sell us their Senior Notes at 101% of the principal amount, plus accrued and unpaid interest.
Chaparral Energy, Inc. is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding Senior Notes have been fully and unconditionally guaranteed, on a joint and several basis, by all of our wholly owned subsidiaries except for Chaparral Biofuels, LLC.
On May 2, 2012, we issued $400,000 aggregate principal amount of 7.625% Senior Notes maturing on November 15, 2022. We used the net proceeds from the issuance to consummate a tender offer for all of our 8.875% Senior Notes due 2017, to redeem the 8.875% Senior Notes not purchased in the tender offer, and for general corporate purposes. Costs totaling $21,714 associated with the refinancing of our 8.875% Senior Notes, including repurchase or redemption-related fees and the write-off of deferred financing costs and unaccreted discount, were recorded as a loss on extinguishment of debt in 2012.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
On November 15, 2012, we issued an additional $150,000 aggregate principal amount of 7.625% Senior Notes under the same indenture covering the issuance on May 2, 2012. The net proceeds from the additional 7.625% Senior Notes issuance were used to repay the outstanding balance of the indebtedness under our senior secured revolving credit facility and for general corporate purposes.
Senior secured revolving credit facility
In April 2010, we entered into an Eighth Restated Credit Agreement (our “senior secured revolving credit facility”), which is collateralized by our oil and natural gas properties and, as amended, matures on November 1, 2017. Availability under our senior secured revolving credit facility is subject to a borrowing base which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once between each scheduled redetermination and in the event of early termination of our derivative contracts. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. If oil and natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural gas properties, the borrowing base may be reduced, thus reducing funds available under the borrowing base.
The initial borrowing base on our senior secured revolving credit facility for 2014 was $600,000. On May 19, 2014, we entered into a Limited Consent and Fourteenth Amendment to our senior secured revolving credit facility which imposed a series of automatic borrowing base reductions as the divestitures of our oil and natural gas properties were completed (see Note 3-Acquisitions and divestitures). As a result of two divestitures that closed during the second quarter and two additional divestitures that closed in July 2014, our borrowing base was reduced to $484,500 effective July 18, 2014. Our semiannual redetermination, effective November 5, 2014, increased our borrowing base to $650,000. Our lenders have completed the semi-annual borrowing base redetermination originally scheduled for May 1, 2015, which has resulted in a decrease of our borrowing base to $550,000 to be effective on April 1, 2015.
Amounts borrowed under our senior secured revolving credit facility are subject to varying rates of interest based on (1) the total outstanding borrowings in relation to the borrowing base (the “utilization percentage”) and (2) whether we elect to borrow at the Eurodollar rate or the Alternate Base Rate (“ABR”). The entire balance outstanding at December 31, 2014 was subject to the Eurodollar rate.
The Eurodollar rate is computed at the Adjusted LIBO Rate, defined as the rate applicable to dollar deposits in the London interbank market with a maturity comparable to the interest period (one, two, three or six months, selected by us) times a Statutory Reserve Rate multiplier, as defined in our senior secured revolving credit facility, plus a margin that varies depending on our utilization percentage. During 2014, the applicable margin varied from 1.75% to 2.00%. Interest payments on Eurodollar borrowings are due the last day of the interest period, if shorter than 3 months or every 3 months.
Interest on loans subject to the ABR is computed as the greater of (1) the Prime Rate, as defined in our senior secured revolving credit facility, (2) the Federal Funds Effective Rate, as defined in our senior secured revolving credit facility, plus 0.50%, or (3) the Adjusted LIBO Rate, as defined in our senior secured revolving credit facility, plus 1.00%, plus a margin that varies depending on our utilization percentage. We did not have loans subject to the ABR during 2014.
Commitment fees of 0.375% to 0.50% accrue on the unused portion of the borrowing base amount, based on the utilization percentage, and are included as a component of interest expense. We have the right to make prepayments of the borrowings at any time without penalty or premium.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Our senior secured revolving credit facility contains restrictive covenants that may limit our ability, among other things, to:
•
incur additional indebtedness;
•
create or incur additional liens on our oil and natural gas properties;
•
pay dividends in cash or other property, redeem our capital stock or prepay certain indebtedness;
•
make investments in or loans to others;
•
change our line of business;
•
enter into operating leases;
•
merge or consolidate with another person, or lease or sell all or substantially all of our assets;
•
sell, farm-out or otherwise transfer property containing proved reserves;
•
enter into transactions with affiliates;
•
issue preferred stock;
•
enter into negative pledge agreements or agreements restricting the ability of our subsidiaries to pay dividends;
•
enter into or terminate certain swap agreements;
•
amend our organizational documents; and
•
amend, modify or waive under our permitted bond documents (i) any covenants that would make the terms materially more onerous to us or (ii) certain other provisions.
Our senior secured revolving credit facility, as amended, also has certain negative and affirmative covenants that require, among other things, maintaining a Current Ratio, as defined in our senior secured revolving credit facility, of not less than 1.0 to 1.0 and a Consolidated Net Debt to Consolidated EBITDAX ratio, as defined in our senior secured revolving credit facility, of not greater than 4.50 to 1.0 for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter. We believe we were in compliance with all covenants under our senior secured revolving credit facility as of December 31, 2014.
Our senior secured revolving credit facility also specifies events of default, including non-payment, breach of warranty, non-performance of financial covenants, default on other indebtedness, certain adverse judgments, and change of control, among others. In addition, bankruptcy and insolvency events with respect to us or certain of our subsidiaries will result in an automatic acceleration of the indebtedness under our senior secured revolving credit facility. An acceleration of our indebtedness under our senior secured revolving credit facility could in turn result in an event of default under the indentures for our Senior Notes, which in turn could result in the acceleration of the Senior Notes.
If the outstanding borrowings under our senior secured revolving credit facility were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay a portion of our bank borrowings in the amount of the excess either in a lump sum within 30 days or in equal monthly installments over a six-month period, (2) to submit within 30 days additional oil and gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and gas properties within 30 days.
We have negotiated an amendment to our senior secured revolving credit facility (the “Fifteenth Amendment”) to be effective April 1, 2015. Among other things, the Fifteenth amendment will replace the Consolidated Net Debt to Consolidated EBITDAX covenant described above with a covenant based on the ratio of Consolidated Net Secured Debt to Consolidated EBITDAX, as defined in the amendment. Under this covenant, we are required to maintain a ratio of Consolidated Net Secured Debt to Consolidated EBITDAX no greater than 2.25 to 1.0 for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter. For the same applicable periods, the Fifteenth Amendment also requires us to maintain an Interest Coverage Ratio, as defined in the amendment, of no less than 2.00 to 1.00. Under the Fifteenth Amendment, we are allowed to incur an additional $300,000 in Additional Permitted Debt, as revised in the amendment to now include both secured and unsecured debt.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Debt issuance costs
The costs that we incur to issue debt includes underwriting and other professional fees. These costs are initially capitalized and are included in “Other assets” in the consolidated balance sheets. The balance of unamortized issuance costs was $20,937 and $23,273 as of December 31, 2014 and 2013, respectively. These costs are amortized as a charge to interest expense using the effective interest method. We recorded amortization of $2,335, $2,197 and $1,694 for the years ended December 31, 2014, 2013 and 2012, respectively.
Capital leases
In 2013, we entered into lease financing agreements with U.S. Bank National Association for $24,500 through the sale and subsequent leaseback of existing compressors owned by us. The carrying value of these compressors is included in our oil and gas full cost pool. The lease financing obligations are for 84-month terms and include the option to purchase the equipment for a specified price at 72 months as well as an option to purchase the equipment at the end of the lease term for its then-current fair market value. Lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.8%. Minimum lease payments are $3,181 annually.
Note 6: Derivative instruments
Overview
Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into various types of derivative instruments, including commodity price swaps, enhanced price swaps, costless collars, put options, and basis protection swaps. See “Note 1-Nature of operations and summary of significant accounting policies” for additional information regarding our accounting policies for derivative transactions.
For commodity price swaps, we receive a fixed price for the hedged commodity and pay a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.
Collars contain a fixed floor price (purchased put) and ceiling price (sold call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party. A three-way collar contract consists of a standard collar contract plus a sold put with a price below the floor price of the collar. The sold put option requires us to make a payment to the counterparty if the market price is below the sold put option price. If the market price is greater than the sold put option price, the result is the same as it would have been with a standard collar contract only. By combining the collar contract with the sold put option, we are entitled to a net payment equal to the difference between the floor price of the standard collar and the sold put option price if the market price falls below the sold put option price. This strategy enables us to increase the floor and the ceiling price of the collar beyond the range of a traditional costless collar utilizing the value associated with the sale of a put option.
We enhance the value of certain oil swaps by combining them with sold puts or put spread contracts. Sold puts require us to make a payment to the counterparty if the market price is below the put strike price at the settlement date. If the market price is greater than the sold put price, the result is the same as it would have been with a swap contract only. A put spread is a combination of a sold put and a purchased put. If the market price falls below the purchased put option price, we will pay the spread between the sold put option price and the purchased put option price from the counterparty. The use of a sold put allows us to receive an above-market swap price while the purchased put provides a measure of downside protection. A put spread may also be constructed by entering into separate sold put and purchased put contracts.
Put options may be purchased from the counterparty by paying a cash premium at the time the put options are purchased or deferring payment until the put options settle. If the market price is below the put strike price at the settlement date, we will receive a payment from the counterparty. Purchased put options are designed to provide a fixed price floor in an environment where prices have declined. In such an environment, put options may also be purchased to offset the downside from sold puts that are originally associated with enhanced swaps or three-way collars. The fair value of our put options include any deferred premiums that are payable under the contract.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
We use basis protection swaps to reduce basis risk. Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. Natural gas basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified pricing point. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract.
We enter into crude oil derivative contracts for a portion of our natural gas liquids production. The following table summarizes our crude oil derivatives outstanding as of December 31, 2014:
____________
(1)
Prior to December 8, 2014, we had outstanding swaps scheduled to mature in 2015 for 5,548,000 barrels of crude oil production that had an associated sold put at $80/barrel and a purchased put at $60/barrel. We also had outstanding swaps scheduled to mature in 2015 for 510,000 barrels of crude oil production that had an associated sold put at $80/barrel and no associated purchased put. On December 8, 2014, we entered into offsetting positions to the sold put and purchased put legs of the swaps described above, effectively terminating those puts and ending with a swap on the associated volumes. Payment of $83,951 for the premiums on the offsetting positions has been deferred until 2015 to coincide with the maturity of the swaps. Premiums of $1,220 were also deferred on the initial $60 purchased puts that are now offset. This results in a total of $85,171 or $14.06 per barrel of deferred premiums related to the above 6,058,000 barrels of crude oil. As a result of offsetting the puts and deferring payment, we now have the above 6,058,000 barrels of crude oil production hedged in 2015 at an effective price of $78.86/barrel.
(2)
Total premiums of $20,609 for the purchased puts were paid at contract inception in December 2014. Excluding the premiums and utilizing an average NYMEX strip price of $62.63 for 2016 as of December 31, 2014, the average realized price from our 3,720,000 barrels of hedged production that have associated sold puts and purchased puts is $75.05/barrel. In the event of further declines in crude oil prices below $60.00/barrel, the purchase of these put options allows us to establish a floor on the realized price for these hedged volumes of $72.42/barrel.
The following tables summarize our natural gas derivative instruments outstanding as of December 31, 2014:
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
On March 26, 2015, we entered into early settlements of certain oil and natural gas derivative contracts originally scheduled to settle between 2015 to 2017 covering 495,000 barrels of oil and 12,280 Bbtu of natural gas for net proceeds of $15,395 in order to maintain compliance with the hedging limits imposed by covenants under our senior secured credit facility. We were in compliance with the aforementioned hedging limits as of March 31, 2015.
Effect of derivative instruments on the consolidated balance sheets
All derivative financial instruments are recorded on the consolidated balance sheets at fair value. See “Note 7-Fair value measurements” for additional information. The estimated fair values of derivative instruments are provided below. The carrying amounts of these instruments are equal to the estimated fair values.
___________
(1)
Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with a counterparty are netted only to the extent that they relate to the same current versus noncurrent classification on the balance sheet.
We discontinued hedge accounting effective April 1, 2010. Net derivative gains (losses) attributable to derivatives previously subject to hedge accounting were deferred through AOCI. As of December 31, 2014, there are no longer any deferred gains in AOCI as all the previously deferred gains (losses) have been reclassified into earnings upon the sale of the hedged production.
Derivative settlements outstanding were as follows at December 31:
Effect of derivative instruments on the consolidated statements of operations
We discontinued hedge accounting effective April 1, 2010. and have since no longer applied hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as non-hedge derivative gains (losses) in the consolidated statements of operations. Net derivative gains (losses) attributable to derivatives previously subject to hedge accounting were deferred through AOCI and upon settlement, were reclassified from AOCI into gain from oil hedging activities which is a component of total revenues in the consolidated statements of operations. As of December 31, 2013, there are no longer any deferred gains in AOCI as all the previously deferred gains (losses) have been reclassified into earnings upon the sale of the hedged production.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Non-hedge derivative gains (losses) in the consolidated statements of operations are comprised of the following:
Note 7: Fair value measurements
Recurring fair value measurements
Our financial instruments recorded at fair value on a recurring basis consist of commodity derivative contracts (see “Note 6-Derivative instruments”). We have no Level 1 assets or liabilities as of December 31, 2014 or December 31, 2013. Our derivative contracts classified as Level 2 as of December 31, 2014 and December 31, 2013 consist of commodity price swaps and basis protection swaps, which are valued using an income approach. Future cash flows from the derivatives are estimated based on the difference between the fixed contract price and the underlying published forward market price, and are discounted at the LIBOR swap rate.
As of December 31, 2014 and December 31, 2013, our derivative contracts classified as Level 3 consisted of three-way collars, enhanced swaps, sold puts and purchased puts. The fair value of these contracts is developed by a third-party pricing service using a proprietary valuation model, which we believe incorporates the assumptions that market participants would have made at the end of each period. Observable inputs include contractual terms, published forward pricing curves, and yield curves. Significant unobservable inputs are implied volatilities. Significant increases (decreases) in implied volatilities in isolation would result in a significantly higher (lower) fair value measurement. We review these valuations and the changes in the fair value measurements for reasonableness.The fair value of our derivative instruments include a measure of our own nonperformance risk for derivative liabilities or that of our counterparties for derivative assets.
The fair value hierarchy for our financial assets and liabilities is shown by the following table:
___________
(1)
Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with a counterparty are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Changes in the fair value of net commodity derivatives classified as Level 3 in the fair value hierarchy at December 31, 2014 and 2013 were:
Nonrecurring fair value measurements
Allocation of purchase price in business combinations. The estimated fair values of proved oil and gas properties and asset retirement obligations assumed in business combinations are based on a discounted cash flow model and market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk-adjusted discount rates. The estimated fair values of unevaluated oil and gas properties was based on geological studies, historical well performance, location and applicable mineral lease terms. Based on the unobservable nature of certain of these assumptions, they are considered Level 3 inputs under the fair value hierarchy. See “Note 3-Acquisitions and divestitures” for additional information regarding our acquisitions.
Asset retirement obligations. Additions to the asset and liability associated with our asset retirement obligations are measured at fair value on a nonrecurring basis. Our asset retirement obligations consist of the estimated present value of future costs to plug and abandon or otherwise dispose of our oil and natural gas properties and related facilities. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, inflation rates, discount rates, and well life, all of which are Level 3 inputs according to the fair value hierarchy. The estimated future costs to dispose of properties added during the years ended December 31, 2014 and 2013 were escalated using an annual inflation rate of 2.95% and 2.95%, respectively, and discounted using our credit-adjusted risk-free interest rate of 7.60% and 6.60%, respectively. These estimates may change based upon future inflation rates and changes in statutory remediation rules. See “Note 8-Asset retirement obligations” for additional information regarding our asset retirement obligations.
Impairment of long-lived assets. During the fourth quarter of 2012, we finalized a plan to dispose of three of our owned drilling rigs by sale that we no longer intended to utilize in oil and natural gas production. The estimated fair value related to the impairment assessment for our three drilling rigs no longer in service was primarily based on broker opinion and, therefore, is classified within Level 3 of the fair value hierarchy. During the years ended December 31, 2013 and 2012, we recognized impairment losses of $3,490 and $2,000, respectively, related to our three drilling rigs no longer in service and drill pipe based on broker opinion. No impairment was recognized on our drilling rigs for the year ended December 31, 2014.
Fair value of other financial instruments
Our significant financial instruments, other than derivatives, consist primarily of cash and cash equivalents, accounts receivable, accounts payable, and long-term debt. We believe the carrying values of cash and cash equivalents, accounts receivable, and accounts payable approximate fair values due to the short-term maturities of these instruments.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
The carrying value and estimated fair value of our long-term debt at December 31, 2014 and 2013 were as follows:
The fair value of our Senior Notes was estimated based on quoted market prices. The carrying value of our senior secured revolving credit facility approximates fair value because it has a variable interest rate and incorporates a measure of our credit risk. The carrying value of our other secured long-term debt approximates fair value because the rates are comparable to those at which we could currently borrow under similar terms.
See “Note 1-Nature of operations and summary of significant accounting policies” for additional information regarding our accounting policies for fair value measurements.
Concentrations of credit risk
Financial instruments which potentially subject us to concentrations of credit risk consist principally of derivative instruments and accounts receivable. Derivative instruments are exposed to credit risk from counterparties. Our derivative contracts are executed with institutions, or affiliates of institutions, that are parties to our senior secured revolving credit facility at the time of execution, and we believe the credit risks associated with all of these institutions are acceptable. We do not require collateral or other security from counterparties to support derivative instruments. Master agreements are in place with each of our derivative counterparties which provide for net settlement in the event of default or termination of the contracts under each respective agreement. As a result of the netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivatives. Our loss is further limited as any amounts due from a defaulting counterparty that is a lender, or an affiliate of a lender, under our senior secured revolving credit facility can be offset against amounts currently due and owing to such counterparty lender under our senior secured revolving credit facility. As of December 31, 2014, the counterparties to our open derivative contracts consisted of ten financial institutions, all ten of which were subject to our rights of offset under our senior secured revolving credit facility.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
The following table summarizes our derivative assets and liabilities which are offset in the consolidated balance sheets under our master netting agreements. It also reflects the amounts outstanding under our senior secured revolving credit facility that are available to offset our net derivative assets due from counterparties that are lenders under our senior secured revolving credit facility.
___________
(1)
Since positive and negative positions with a counterparty are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification, these represent remaining amounts that could have been offset under our master netting agreements.
We did not post additional collateral under any of these contracts as all of our counterparties are secured by the collateral under our senior secured revolving credit facility. Payment on our derivative contracts would be accelerated in the event of a default on our senior secured revolving credit facility. The aggregate fair value of our derivative liabilities subject to acceleration in the event of default was $309 at December 31, 2014.
Accounts receivable are primarily from purchasers of oil and natural gas products, and exploration and production companies who own interests in properties we operate. The industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic, industry or other conditions.
Commodity sales to two purchasers accounted for 23.7% and 14.0% of total commodity sales, excluding the effects of hedging activities, during the year ended December 31, 2014. Commodity sales to two purchasers accounted for 20.1% and 19.1% of total commodity sales, excluding the effects of hedging activities, during the year ended December 31, 2013. Commodity sales to three purchasers accounted for 19.6% and 13.9%, and 12.7% of total commodity sales, excluding the effects of hedging activities, during the year ended December 31, 2012. If we were to lose a purchaser, we believe we could replace them with a substitute purchaser.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Note 8: Asset retirement obligations
The following table presents the balance and activity of our asset retirement obligations for the years ended December 31, 2014 and 2013.
Liabilities incurred and assumed includes obligations related to new wells drilled and wells acquired during the period. Liabilities settled or disposed for the year ended December 31, 2014 increased significantly primarily due to the divestiture of certain non-strategic oil and natural gas properties sold during 2014 combined with increased plugging and abandoning activity.
We have funds held in escrow that are legally restricted for certain of our asset retirement obligations. The balance of this escrow account was $1,568 and $1,568 at December 31, 2014 and 2013, respectively, and is included in “Other assets” in our consolidated balance sheets. The balance is not intended to reflect our total future financial obligation for the plugging and abandonment of these wells.
See “Note 7-Fair value measurements” for additional information regarding fair value measurements.
Note 9: Income taxes
Income tax expense consists of the following for the years ended December 31:
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Income tax expense differed from amounts computed by applying the U.S. Federal income tax rate as follows for the years ended December 31:
Components of the deferred tax assets and liabilities are as follows at December 31:
Approximately $(67,352) and $2,252 of the current deferred tax (liability) asset at December 31, 2014 and 2013, respectively, relates to our short-term derivative instruments. Additionally, the current deferred tax asset (liability) includes an asset of approximately $1,553 and $656 related to asset retirement obligations at December 31, 2014 and 2013, respectively. At December 31, 2014 and 2013, taxes receivable of $336 and $434, respectively, are included in accounts receivable.
We have federal net operating loss carryforwards of approximately $347,000 at December 31, 2014, which will expire between 2027 and 2034 if unused. At December 31, 2014, we have state net operating loss carryforwards of approximately $386,000, which will expire between 2015 and 2032 if unused. In addition, at December 31, 2014 we had federal percentage depletion carryforwards of approximately $11,000, which are not subject to expiration.
At December 31, 2014, approximately $262,000 of the state net operating loss carryforwards have been reduced by a valuation allowance based on our assessment that it is more likely than not that a portion will not be realized.
Realization of our deferred tax assets is dependent upon generating sufficient future taxable income. Although realization is not assured, we believe it is more likely than not that our deferred tax assets will be realized. The amount of our deferred tax assets considered realizable, however, could be reduced in the near-term if estimates of future taxable income are reduced.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Note 10: Stock-based compensation
Phantom Stock Plan and Restricted Stock Unit Plan
Effective January 1, 2004, we implemented a Phantom Unit Plan, which was revised on December 31, 2008 as the Second Amended and Restated Phantom Stock Plan (the “Plan”), to provide deferred compensation to certain key employees (the “Participants”). Phantom stock may be awarded to Participants in total up to 2% of the fair market value of the Company. No Participant may be granted, in the aggregate, more than 5% of the maximum number of phantom shares available for award. Under the Plan, awards vest at the end of five years, but may also vest on a pro-rata basis following a Participant’s termination of employment with us due to death, disability, retirement or termination by us without cause. Also, phantom stock will vest if a change of control event occurs. Phantom shares are cash-settled within 120 days of the vesting date.
Effective March 1, 2012, we implemented a Non-Officer Restricted Stock Unit Plan (the “RSU Plan”) to create incentives to motivate Participants to put forth maximum effort toward the success and growth of the Company and to enable us to attract and retain experienced individuals who by their position, ability and diligence are able to make important contributions to the Company’s success. The RSU Plan is intended to replace the Phantom Plan. Although the Phantom Plan remains in effect, we do not expect to make any further awards under the Phantom Plan.
Restricted stock units may be awarded to Participants in total up to 2% of the fair market value of the Company. Under the RSU Plan, awards generally vest in equal annual increments over a three-year period. RSU awards may also vest following a Participant’s termination of employment in combination with the occurrence of a change of control event, as specified in the RSU Plan. RSU awards are cash-settled, generally within 120 days of the vesting date.
A summary of our phantom stock and RSU activity during the three years ended December 31, 2014 is presented in the following table:
Based on an estimated fair value of $3.83 per phantom share and RSU as of December 31, 2014, the aggregate intrinsic value of the unvested phantom shares and RSUs outstanding was $2,269.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
2010 Equity Incentive Plan
We adopted the Chaparral Energy, Inc. 2010 Equity Incentive Plan (the “2010 Plan”) on April 12, 2010. The 2010 Plan reserves a total of 86,301 shares of our class A common stock for awards issued under the 2010 Plan. All of our or our Affiliated Entities’ employees, officers, directors, and consultants, as defined in the 2010 Plan, are eligible to participate in the 2010 Plan.
The awards granted under the 2010 Plan consist of shares that are subject to service vesting conditions (the “Time Vested” awards) and shares that are subject to market and performance vested conditions (the “Performance Vested” awards). The Time Vested awards vest in equal annual installments over the five-year vesting period, but may also vest on an accelerated basis in the event of a transaction whereby CCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively “CCMP”) receive cash upon the sale of its class E common stock (a “Transaction” as defined in the restricted stock agreements). The Performance Vested awards vest in the event of a Transaction that achieves certain market targets as defined in the 2010 Plan. Any shares of Performance Vested awards not vested on a Separation Date (as defined in the 2010 Plan) will be forfeited as of the Separation Date.
Our 2010 Plan allows participants to elect, upon vesting of their Time Vested awards, to have us withhold shares having a fair market value greater than the minimum statutory withholding amounts for income and payroll taxes that would be due with respect to such vested shares. As a result of this provision, the Time Vested awards are classified as liability awards under accounting guidance and remeasured to fair value at the end of each reporting period. The Performance Vested awards are classified as equity awards and are not remeasured to fair value at the end of each reporting period subsequent to grant date.
Effective January 1, 2013, we amended and restated the Performance Vested awards to reflect that: (i) those shares which would vest if CCMP receives net cash proceeds from a Transaction that yields a return of at least 400% per share, or 20% of the Performance Vested awards then outstanding, were removed from the initial Performance Vested awards and an equal number of Time Vested shares were granted effective as of January 1, 2013; and (ii) the remaining number of Performance Vested shares outstanding were reallocated among five targets for vesting. Effective October 1, 2014, we terminated all outstanding grants of Performance Vested awards and issued new grants of Performance Vested awards to reflect that (i) a certain number of shares which would vest if CCMP receives net proceeds from a Transaction that yields a return of at least 350% per share were removed from the initial Performance Vested awards and an equal amount were granted effective as of October 1, 2014, as Time Vested awards; and (ii) the remaining number of shares subject to the previous Performance Vested awards were reallocated among three targets for vesting. These vesting targets will apply for any new grants of Performance Vested awards. As a result of these modifications, vesting requirements for all remaining Performance Vested awards are set at the following levels:
The modifications above changed the classification of the canceled and reissued awards from equity to liability instruments. The modifications in 2014 and 2013 both resulted in estimated incremental compensation cost of $8,536 and $4,322, which will be recognized over the remaining requisite service period using the accelerated method. Incremental compensation cost is measured as the excess of the fair value of the modified award over the fair value of the original award immediately before the modification, and is adjusted for changes in the fair value of the modified awards in each period until the awards are vested or forfeited.
A combined income and market valuation methodology was used to estimate the fair value of our common equity per share. The fair value of the Time Vested awards granted during 2014, 2013, and 2012 was considered to be equal to the estimated fair value of our common equity per share, net of a discount for lack of control of 0% , 0%, and 23% and a discount for lack of marketability of 20%, 17%, and 22%, respectively. A control discount was not applied in 2014 or 2013 pursuant to guidance released by the AICPA in 2013 that discourages incorporating a control premium in the enterprise value used in valuing minority interest securities within an enterprise, except to the extent that such a premium reflects improvements to the business that a market participant would expect under current ownership.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
The Monte Carlo simulation method was used to value the Performance Vested awards. A Monte Carlo simulation allows for the analysis of a complex security through statistical measures applied to a model that is simulated thousands of times to build distributions of potential outcomes. The variables and assumptions used in this calculation were as follows:
Our expected volatility was calculated based on the average of the historical stock price volatility and the volatility implicit in the prices of the options or other traded financial instruments of our peer group. Our peer group consisted of the following oil and natural gas exploration and production companies in 2014: Cimarex Energy Co., Denbury Resources, Inc., Jones Energy, Inc., Laredo Petroleum Holdings, Inc., Midstates Petroleum Company, Inc., Pioneer Natural Resources Co., Resolute Energy Corporation, Sandridge Energy, Inc., Whiting Petroleum Corp. and Newfield Exploration Co. Our peer group in 2013 consisted of Cimarex Energy Co., Denbury Resources, Inc., Jones Energy, Inc., Laredo Petroleum Holdings, Inc., Midstates Petroleum Company, Inc., Pioneer Natural Resources Co., Resolute Energy Corporation, Sandridge Energy, Inc., and Whiting Petroleum Corp. Our peer group in 2012 consisted of Berry Petroleum Co., Concho Resources, Inc., Continental Resources, Inc., Denbury Resources, Inc., Laredo Petroleum Holdings, Inc., Pioneer Natural Resources Co., Sandridge Energy, Inc., and Whiting Petroleum Corp.
A summary of our Time and Performance award activity during the three years ended December 31, 2014 is presented in the following table:
During 2014, 2013, and 2012, respectively, we repurchased and canceled 2,025, 1,025, and 1,469 vested shares, primarily for tax withholding, and we expect to repurchase approximately 3,000 restricted shares vesting during the next twelve months. Based on an estimated fair value of $533.80 per Time Vested restricted share, the aggregate intrinsic value of the unvested Time Vested restricted shares outstanding was $13,790 as of December 31, 2014.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Stock-based compensation cost
A portion of stock-based compensation cost associated with employees involved in our acquisition, exploration, and development activities has been capitalized as part of our oil and natural gas properties. The remaining cost is reflected in lease operating and general and administrative expenses in the consolidated statements of operations. We recognized stock-based compensation expense as follows for the years ended December 31:
Payments for stock-based compensation were $2,995, $1,533, and $1,386 during 2014, 2013, and 2012, respectively. As of December 31, 2014 and 2013, accrued payroll and benefits payable included $4,830 and $5,081, respectively, for stock-based compensation costs expected to be settled within the next twelve months. Unrecognized stock-based compensation cost of approximately $15,227 as of December 31, 2014 is expected to be recognized over a weighted-average period of 2.5 years.
Note 11: Stockholders’ equity
Common Stock
Our Amended and Restated Certificate of Incorporation filed April 12, 2010, created seven classes of $0.01 par value per share common stock, classes A through G, with the rights and preferences summarized below. The class A common stock carries standard voting, dividend and liquidation rights. The class B, C and D common stock was issued to our existing stockholders, with a separate class issued to each stockholder. The class E and class F common stock was issued to CCMP. One share of class G common stock was issued to each of our existing stockholders.
On January 13, 2014, CHK Energy Holdings Inc. (“CHK Energy Holdings”), an indirect wholly owned subsidiary of Chesapeake Energy Corporation (“Chesapeake”), sold all of its equity interest in us to Healthcare of Ontario Pension Plan Trust Fund. The 279,999 class D shares and one class G share owned by CHK Energy Holdings automatically converted to class A common stock and all associated rights with the class D and class G common stock were terminated.
All remaining shares of class B through G common stock will automatically convert to class A common stock upon consummation of an initial public offering of shares of class A common stock resulting in proceeds to us of at least $250,000, which is underwritten on a firm commitment basis by a nationally recognized investment banking firm, and which results in the initial listing or quotation of the class A common stock on any national securities exchange (a “Qualified IPO”).
Holders of class B and C common stock have the right, in aggregate, to designate three directors. Holders of class E common stock have the right to designate two directors.
The class B, E, F and G common stock carry the following additional voting and consent rights:
•
So long as the class B holders own 80% or more of the common stock they owned as of April 12, 2010, the closing date of our initial Stockholders Agreement (the “Original Date”), and without such holder’s prior consent, we may neither initiate nor consummate a sale of the Company, whether in the form of a stock sale, asset sale, merger or any other form whatsoever (a “Company Sale”), or a liquidation or dissolution of the Company, on or prior to the sixth anniversary of the Original Date.
•
In certain circumstances, we are prohibited from incurring debt, consummating sales or acquisitions of assets, taking certain operational actions or engaging in other specified transactions without the prior consent of the holders of the class E common stock.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
•
Upon the triggering of a Company Sale or a Demand IPO (each as summarized below) by holders of class E common stock, the voting and other rights related to the class F common stock will permit holders of class E common stock to cause any actions necessary to be taken by our board of directors or stockholders to consummate such Company Sale or Demand IPO.
•
Upon the triggering of a Demand IPO by a majority in interest of our existing stockholders, the voting and other rights related to the class G common stock will permit the majority of the holders of class G common stock to cause any actions necessary to be taken by the Company’s board of directors or stockholders to consummate such Demand IPO.
The rights and preferences of a holder of class B, C, E, F and G common stock terminate on the earlier of (x) the closing date of a Qualified IPO or (y) the date that such holder and its permitted transferees cease to beneficially own 5% or more of our fully-diluted common stock.
Stockholders Agreement
Effective April 12, 2010, we implemented a Stockholders Agreement to provide for certain general rights and restrictions, including board observer rights, informational rights, general restrictions on transfer of common stock, tag-along rights, preemptive rights, registration rights following a Qualified IPO and, subject to certain limited exceptions, prohibitions on the sale or acquisition of our common stock that would result in a change of control, as such term is defined under the indentures for our Senior Notes. The Stockholders Agreement was amended and restated on January 12, 2014 in conjunction with the sale of Chesapeake’s ownership interest in us to Healthcare of Ontario Pension Plan Trust Fund.
Our Stockholders Agreement, as amended, also provides for the following stockholder-specific rights or restrictions:
•
Prior to a Qualified IPO, Altoma Energy GP (“Altoma”) will not vote for the approval of (i) any merger, consolidation, conversion or a Demand IPO, (ii) certain amendments to our organizational documents, (iii) the sale of all or substantially all of our assets, or (iv) a termination of the business of or liquidation or dissolution of the Company, unless Fischer Investments, L.L.C. (“Fischer”) votes for such approval.
•
Other than pursuant to the exercise of preemptive rights, Healthcare of Ontario Pension Plan Trust Fund may not acquire more than 25% of our outstanding common stock.
•
CCMP may sell up to 20% of its common stock owned on the Original Date without restriction. Prior to a Qualified IPO and except in limited circumstances, CCMP is restricted from making further sales before the fourth anniversary of the Original Date, and any sales thereafter (but before a Qualified IPO) will be subject to certain rights of first offer provisions set forth in the Stockholders Agreement (the “ROFO provisions”).
•
Fischer may sell up to 20% of its common stock owned immediately prior to the Original Date subject to certain restrictions. Prior to a Qualified IPO and except in limited circumstances, Fischer is restricted from making further sales before the fourth anniversary of the Original Date, and any sales thereafter (but before a Qualified IPO) will be subject to the ROFO provisions.
•
Altoma may request to transfer its shares pursuant to a demand registration, but only after Altoma first offers such shares to the Company, and then to Fischer and CCMP in accordance with the procedures set forth in the Stockholders Agreement.
•
Either (i) CCMP or (ii ) a majority in interest of Fischer and Altoma may demand that we engage in a Qualified IPO (a “Demand IPO”), if (a) the price per share to be received by the Company or such party or parties, as the case may be, in such Demand IPO is at least 1.75 times the price per share paid by CCMP for our common stock pursuant to the Stock Purchase Agreement and (b) certain other conditions are met.
•
At any time after the four year anniversary of the Original Date, CCMP may demand a Demand IPO.
•
At any time after the sixth anniversary of the Original Date, and so long as a Qualified IPO has not yet occurred, CCMP may demand a Company Sale, subject to a right of first offer to purchase the Company provided to Fischer.
With the exception of registration rights, the rights and preferences of a stockholder under the amended and restated Stockholders Agreement will generally terminate on the earlier of (x) the closing date of a Qualified IPO or (y) the date that such holder and its permitted transferees cease to beneficially own 5% or more of our fully-diluted common stock.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Summary of changes in common stock
The following is a summary of the changes in our common shares outstanding during the years ended December 31, 2014, 2013 and 2012:
________________
(1) In this transaction, Healthcare of Ontario Pension Plan Trust Fund (“HOOPP”) purchased 280,000 shares of Class A common stock converted from Class D and Class G common stock held by CHK Energy Holdings, Inc. (“CHK Energy Holdings”) on January 13, 2014. An additional 15,078 shares of Class A common stock was purchased by HOOPP from various other stockholders of which 13,023 shares were converted from Class B common stock.
Note 12: Retirement benefits
We provide a 401(k) retirement plan for all employees and matched 100% of employee contributions up to 7% of each employee’s gross wages during 2014 and 2013 and matched 6% during 2012. At December 31, 2014, 2013, and 2012, there were 625, 585, and 661 employees, respectively, participating in the plan. Our contribution expense was $3,592, $3,621, and $2,809 for the years ended December 31, 2014, 2013 and 2012, respectively.
Note 13: Commitments and contingencies
Letters of Credit. Standby letters of credit (“Letters”) available under our senior secured revolving credit facility are used in lieu of surety bonds with various organizations for liabilities relating to the operation of oil and natural gas properties. We had an outstanding amount of $920 and $920 as of December 31, 2014 and 2013, respectively. Interest on each Letter accrues at the lender’s prime rate for all amounts paid by the lenders under the Letters. No amounts were paid by the lenders under the Letters, therefore we paid no interest on the Letters during the years ended December 31, 2014, 2013, or 2012.
Commitments. We have four long-term contracts with four different suppliers to purchase CO2. Contract terms range from 2 to 20 years and provide for renewal or cancellation upon the occurrence of specific future events. Pricing under one of these contracts is fixed. Pricing under two of the contracts varies with the price of oil. The fourth contract provides fixed pricing through 2018 but becomes dependent upon the price of oil in subsequent years. Under this contract, we are obligated to purchase an average of approximately 35 MMcf/d for the remaining contract term or pay for any deficiencies at the price in effect when the minimum delivery was to have occurred. After the first ten contract years, we may permanently reduce up to 100% of our purchase rate with six months’ notice.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
As of December 31, 2014, we were purchasing approximately 68 MMcf/d of CO2, from all sources combined and we expect to purchase between 68 MMcf/d to 71 MMcf/d over the remaining contract terms. Purchases under these contracts were $4,890, $3,849, and $3,860 during 2014, 2013, and 2012, respectively.
Based on current prices, our estimated minimum purchase obligations under our CO2 contracts are as follows:
Operating Leases. We rent equipment used on our oil and natural gas properties and have operating lease agreements for CO2 recycle compressors and office equipment. Rent expense for the years ended December 31, 2014, 2013, and 2012 was $11,088, $8,967, and $8,144, respectively. Our leases relating to office equipment have terms of up to five years. In June 2014, we entered into two non-cancelable operating leases for CO2 recycle compressors at our EOR facilities which expire in 2021.
As of December 31, 2014, total remaining payments associated with our operating leases were:
Other Contingencies. We have entered into change of control severance agreements under which our officers are entitled to receive certain severance benefits. The severance payment will be paid in equal monthly installments over a period of months as calculated under the terms of the agreement and will be equal to a set multiplier times the sum of (A) the officer’s base salary as in effect immediately prior to their termination date, plus (B) the officer’s bonus for the full year in which the termination date occurred. As of December 31, 2014, the maximum amount payable under these agreements in the event of a change in control that results in our officers being terminated is $10,833.
Litigation and Claims
Naylor Farms, Inc., individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On June 7, 2011, an alleged class action was filed against us in the United States District Court for the Western District of Oklahoma (“Naylor Farms Case”) alleging that we improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners as categorized in the petition from crude oil and natural gas wells located in Oklahoma. The purported class includes non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. The plaintiffs have alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. We have responded to the Naylor Farms petition, denied the allegations and raised arguments and defenses. Discovery is ongoing and information and documents continue to be exchanged. The class has not been certified, but the motion for class certification is due in the fourth quarter of 2015. We are not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the Naylor Farms Case will have on our financial condition, results of operations or cash flows due to the preliminary status of the matters, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the potential size of the class, the scope and types of the properties and agreements involved, and the ultimate potential outcome of the matter. Plaintiffs in the Naylor Farms Case have indicated that, if the class is certified, they seek damages in excess of $5,000 which may increase with the
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
passage of time, a majority of which would be comprised of interest. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.
Amanda Dodson, individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On May 10, 2013, Amanda Dodson (the “Plaintiff”), filed a complaint against us in the District Court of Mayes County, Oklahoma, (“Dodson Case”) with allegation similar to those asserted in the Naylor Farms case related to post-production deductions, and include clams for breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. The alleged class includes non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. We have responded to the Dodson petition, denied the allegations and raised a number of affirmative defenses. At this time, a class has not been certified and discovery has not yet commenced. We are not currently able to estimate a reasonable possible loss or range of loss or what impact, if any, the Dodson Case will have on its financial condition, results of operations or cash flows due to the preliminary status of the matters, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the potential size of the class, the scope and types of the properties and agreements involved, and the ultimate potential outcome of the matter. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.
Martha Donelson and John Friend, on behalf of themselves and on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On August 11, 2014, an alleged class action was filed against us, as well as several other operators in Osage County, in the United States District Court for the Northern District of Oklahoma (“Donelson Case”), alleging claims on behalf of the named plaintiffs and all similarly situated Osage County land owners and surface lessees. The Plaintiffs assert claims seeking recovery for trespass, nuisance, negligence and unjust enrichment. Relief sought includes declaring oil and natural gas leases and drilling permits obtained in Osage County without a prior NEPA study void ab initio, removing us from all properties owned by the class members, disgorgement of profits, and compensatory and punitive damages. We have joined in Motions to Dismiss filed by the Defendants. At this time, a class has not been certified and discovery has yet to begin. As such, we are not yet able to estimate a possible loss, or range of possible loss, if any. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.
We are involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, employment claims, and other matters which arise in the ordinary course of business. While the outcome of these legal proceedings cannot be predicted with certainty, we do not expect any of them individually to have a material effect on our financial condition, results of operations or cash flows.
Note 14: Oil and natural gas activities
Our oil and natural gas activities are conducted entirely in the United States. Costs incurred in oil and natural gas producing activities are as follows for the years ended December 31:
________________
(1)
Includes $152, $37,344, and $52,188 of EOR costs in 2014, 2013, and 2012, respectively.
Depreciation, depletion, and amortization expense of oil and natural gas properties was $231,761, $179,734, and $154,788 for the years ended December 31, 2014, 2013, and 2012, respectively. The average depreciation, depletion and amortization rate per equivalent unit of production was $21.10, $18.45, and $16.98 for the years ended December 31, 2014, 2013, and 2012, respectively.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Oil and natural gas properties not subject to amortization consist of the cost of unevaluated properties and seismic costs associated with specific unevaluated properties. Of the $288,425 of unproved property costs at 2014 being excluded from the amortization base, $102,860, $122,494, and $62,092 were incurred in 2014, 2013, and 2012, respectively, and $979 was incurred in prior years. We expect to complete our evaluation for the majority of these costs relating to non-EOR properties within the next two to five years.
Note 15: Disclosures about oil and natural gas activities (unaudited)
The estimate of proved reserves and related valuations were based upon the reports of Cawley, Gillespie & Associates, Inc. and Ryder Scott Company, L.P., each independent petroleum and geological engineers, and our engineering staff. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time.
Our oil and natural gas reserves are attributable solely to properties within the United States. A summary of the changes in our quantities of proved oil and natural gas reserves for the three years ended December 31, 2014 are as follows:
________________
(1)
Includes natural gas liquids.
(2)
The downward revision in our reserves during 2012 was primarily due to a decrease in both oil and natural gas pricing used to estimate the reserves.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
________________
(1)
The downward revision in our reserves during 2014 was primarily due to removing proved undeveloped reserves that are not expected to be developed within the five-year time frame mandated by the SEC and a decline in the estimated sales margin on natural gas. The downward revision in our reserves during 2013 was primarily due to removing proved undeveloped reserves that are not expected to be developed within the five-year time frame and to negative technical revisions. The 2013 downward revisions were partially offset by positive revisions due to improved pricing of oil and natural gas.
The following information was developed using procedures prescribed by GAAP. The standardized measure of discounted future net cash flows should not be viewed as representative of our current value. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating us or our performance.
We believe that, in reviewing the information that follows, the following factors should be taken into account:
•
future costs and sales prices will probably differ from those required to be used in these calculations;
•
actual rates of production achieved in future years may vary significantly from the rates of production assumed in the calculations;
•
a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and
•
future net revenues may be subject to different rates of income taxation.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Future cash inflows used in the standardized measure calculation were estimated by applying a twelve-month average price for oil, gas and natural gas liquids, adjusted for location and quality differences, to the estimated future production of year-end proved reserves. Future cash inflows do not reflect the impact of future production that is subject to open derivative positions (see “Note 6-Derivative instruments”). Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs in order to arrive at net cash flows before tax. Future income tax expense has been computed by applying year-end statutory tax rates to aggregate future pre-tax net cash flows reduced by the tax basis of the properties involved and tax carryforwards. GAAP requires the use of a 10% discount rate and prices and costs excluding escalations based upon future conditions.
In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:
The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
The following prices for oil, natural gas, and natural gas liquids before field differentials were used in determining future net revenues related to the standardized measure calculation.
________________
(1)
The NGL price is provided only for 2014 and 2013 to coincide with our separate presentation of NGL reserves in those years.
Note 16: Subsequent events
On February 2, 2015, we began implementation of a workforce reduction plan (the “Plan”) as part of a Company-wide effort to decrease our capital, operating and administrative costs. The Plan resulted in a total reduction of 180 employees, of which 121 were located in the Oklahoma City headquarters office and 59 were located at various field offices. All employees impacted by the Plan were notified by February 4, 2015. In connection with the Plan, we estimate that we will pay approximately $9,994 of one-time termination benefits. Of the estimated amount of one-time termination benefits, $3,356 relates to amounts previously accrued by us while the remaining $6,638 will be recorded as an expense during the first quarter of 2015.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
We have established disclosure controls and procedures to ensure that material information relating to us, including our consolidated subsidiaries, is made known to the officers who certify our financial reports and to other members of senior management and the board of directors. Based on their evaluation as of the end of the fiscal year ended December 31, 2014, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and are effective to ensure that information required to be disclosed in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
Management’s Report on Internal Control over Financial Reporting
Internal control over financial reporting is defined in Rule 13a-15(f) and 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended, as a process designed by, or under the supervision of, our principal executive and principal financial officers, or persons performing similar functions, and effected by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with U.S. generally accepted accounting principles and includes those policies and procedures that:
•
pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions relating to and the dispositions of our assets;
•
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
•
provide reasonable assurance regarding prevention or the timely detection of unauthorized acquisition, or the use or disposition of our 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. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Additionally, 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.
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in the 2013 Internal Control-Integrated Framework, management concluded that our internal control over financial reporting was effective as of December 31, 2014.
This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during the three months ended December 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We may make changes in our internal control procedures from time to time in the future.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Executive Officers and Directors
The following table provides information regarding our executive officers and directors. Our board of directors currently consists of five members: Mark A. Fischer, K. Earl Reynolds, Charles A. Fischer, Jr., Christopher Behrens, and Kyle Vann. Mark A. Fischer and K. Earl Reynolds are full-time employees.
Mark A. Fischer, Chairman and Chief Executive Officer, and Co-Founder, co-founded Chaparral in 1988 and has served as its Chief Executive Officer and Chairman of the Board since its inception and President from inception to December 31, 2014. Mr. Fischer began his career with Exxon Company USA in 1972 in the Permian Basin of West Texas where he held various positions as production engineer, reservoir engineer, field superintendent and finally supervising production engineer. From 1977 until 1980, Mr. Fischer served as the drilling and production manager for the West Texas and then Mid-Continent Division of TXO Production Corp. Prior to founding Chaparral, he served as division operations manager for Slawson Exploration Company from 1980 until 1988, focusing on the Mid-Continent and Panhandle Divisions. He is a member of the Society of Petroleum Engineers and the American Petroleum Institute (API). Mr. Fischer served as a director of the API from 1984-1986. He currently sits on the Board of Directors of Pointe Vista Development, LLC and several non-profit organizations including the Boy Scouts of America, the Texas A&M Look College of Engineering Advisory Council and Texas A&M Association of Former Students. Mr. Fischer graduated from Texas A&M University in 1972 with an honors degree in aerospace engineering. He was named as a Distinguished Alumni in Aerospace Engineering and a recipient of the College of Engineering Outstanding Alumni Award in 2014. Mark A. Fischer and Charles A. Fischer, Jr. are brothers. Mr. Fischer is the board designee of the holders of our class B common stock.
K. Earl Reynolds, President and Chief Operating Officer, joined Chaparral in February 2011 as our Chief Operating Officer and Executive Vice President. Mr. Reynolds became our President effective January 1, 2014. From 2000 to 2010, Mr. Reynolds led the international business unit and was actively involved in strategic planning for Devon Energy, most recently serving as Senior Vice President of Strategic Development, where he was responsible for strategic planning, budgeting, coordination of acquisitions and divestitures, and oversight of the company’s assessment of oil and gas reserves. Prior to Devon Energy, Mr. Reynolds’ career included several key leadership roles in domestic and international operations with companies such as Burlington Resources and Mobil Oil. Mr. Reynolds is registered as a Professional Engineer and a member of the Society of Petroleum Engineers. Mr. Reynolds has served on the board of directors for several non-profit organizations in Houston and Oklahoma City. He currently sits on the Board of Directors for the Oklahoma Independent Petroleum Association and serves as the Chairman of its Crude Oil Committee. Mr. Reynolds holds a Master of Science degree in Petroleum Engineering from the University of Houston and a Bachelor of Science degree in Petroleum Engineering from Mississippi State University. In 2013, he was named as a Distinguished Fellow of the Mississippi State University Bagley College of Engineering. Mr. Reynolds is the second board designee of the holders of our class B common stock.
Joseph O. Evans, Chief Financial Officer and Executive Vice President, joined Chaparral in July of 2005 as Chief Financial Officer and Executive Vice President. From 1998 to 2005, Mr. Evans was a consultant and practiced public accounting with the firm of Evans Gaither & Assoc. From 1997 to 1998, he served as Senior Vice President and Financial Advisor, Energy Lending, for First National Bank of Commerce in New Orleans. From 1976 until 1997, Mr. Evans worked in the Oklahoma practice of Deloitte & Touche where he became an Audit Partner. While at Deloitte he was a member of the energy industry group and was responsible for services on numerous Commission filings for clients. Mr. Evans has instructed numerous continuing professional education courses focused on compliance with the Sarbanes Oxley Act. He is a Certified Public Accountant and an Accredited Petroleum Accountant. Mr. Evans is a graduate of the University of Central Oklahoma with a Bachelor of Science degree in Accounting.
James M. Miller, Sr. Vice President-Enhanced Oil Recovery, joined Chaparral in 1996 as Operations Engineer. Since joining Chaparral, Mr. Miller has been promoted to positions of increasing responsibility and currently oversees the Company’s production and completion operations. During this time, he has gained particular expertise in the area of operating secondary and tertiary recovery units. Prior to joining Chaparral, Mr. Miller worked for KEPCO Operating Inc. as a petroleum engineer. From 1987 to 1995, he was employed by Robert A. Mason Production Co., as a petroleum engineer, and later as Vice President of Production. He is a member of the Society of Petroleum Engineers and the American Petroleum Institute. Mr. Miller attended the University of Oklahoma and received a Bachelor of Science degree in Petroleum Engineering.
Jeffery D. Dahlberg, Sr. Vice President-Exploration and Production, joined Chaparral in 2007 as District Manager of the Mid-Continent West Division. Since joining the Company, Mr. Dahlberg has been promoted to positions of increasing responsibility and currently serves as Senior Vice President of Resource Development. Mr. Dahlberg held numerous key technical and senior management positions at Windsor Energy from 2003 to 2007. including serving as its Chief Operating Officer. Before that time, his career included several technical and management roles with Enserch Exploration, Texas Oil and Gas, and Twister Gas Services. Mr. Dahlberg is a member of the Society of Petroleum Engineers and holds a Bachelor of Science degree in Petroleum Engineering from Louisiana Tech University.
David R. Winchester, Sr. Vice President-Drilling Operations, joined Chaparral in 2014 as Senior Vice President of Drilling Operations. Before joining Chaparral, Mr. Winchester served as Vice President of Drilling Operations at Chesapeake Energy Corporation where he spearheaded the construction of infrastructure and establishment of drilling programs in the Fayetteville, Haynesville and Eagle Ford Shale areas, as well as material drilling programs in the Mid-Continent. Mr. Winchester has more than 30 years of onshore oil and natural gas drilling experience. Prior to Chesapeake, he served as a drilling manager at Anadarko Petroleum Corporation and the co-owner of Winmill Petroleum. During the early portion of his career, he was employed by Chevron USA and Gulf Oil. He is a member of the Society of Petroleum Engineers, International Association of Drilling Contractors, American Petroleum Institute and American Association of Drilling Engineers. Mr. Winchester holds a Master’s of Science in petroleum engineering and a Juris Doctor degree from the University of Oklahoma.
John D. Wehrle, Sr. Vice President-Business Development and Finance, joined Chaparral in 2014 as Senior Vice President of Business Development and Finance. Prior to joining Chaparral, Mr. Wehrle served as Managing Director and Co-Head of U.S. Operations for Scotia Waterous, a global energy advisory firm, where he oversaw U.S. investment banking and provided strategic advice regarding acquisition, divestiture, merger and corporate restructuring opportunities for E&P clients. Mr. Wehrle has approximately two decades of investment banking and upstream E&P corporate finance experience. His prior investment banking experience includes nearly a decade at Goldman Sachs & Co. and RBC Dominion Securities, while his direct industry exposure includes time spent at both private equity-backed and public companies, including Bill Barrett Corporation and Vantage Energy. Mr. Wehrle holds a Bachelor of Commerce (Honours) degree from the University of Manitoba.
Charles A. Fischer, Jr., Director and Co-Founder, co-founded Chaparral in 1988 and has served as a director since its inception. Mr. Fischer joined Chaparral full-time in 2000 and served as Chief Financial Officer, Senior Vice President and Chief Administrative Officer before retiring in 2007. Mr. Fischer serves as a managing partner of Altoma Energy GP and as President of C.A. Fischer Lumber Co. Ltd. which he formed in 1978 in western Canada. He began his career with Renewable Resources in 1974 as a senior scientist on the Polar Gas Pipeline Project investigating the feasibility of bringing natural gas from the high Arctic to south central Canada. Mr. Fischer has served as director and President of the Canadian Western Retail Lumberman’s Association and received the 2001 Industry Achievement Award. He graduated from Texas A&M University with a Bachelor of Science degree in Biology and from the University of Wisconsin with a Master of Science degree in Ecology. Mr. Fischer is a brother to Mark Fischer. Mr. Fischer is the board designee of the holders of our class C common stock.
Christopher Behrens, Director, joined the Board of Directors of the Company in April 2010 as a nominee of CCMP Capital Advisors, LLC. Mr Behrens is a Managing Director in the New York office of CCMP Capital and a member of the firm’s Investment Committee. Mr. Behrens focuses on making investments in the energy, industrial and distribution sectors. Prior to joining CCMP in 1994, he was a Vice President in the Merchant Banking group of The Chase Manhattan Corporation. Mr. Behrens also serves on the board of directors of Newark E&P Holdings, LLC and Noble Environmental Power, LLC. Mr. Behrens holds a B.A. from the University of California, Berkeley and an M.A. from Columbia University. Mr. Behrens is one of the two board designees of the holders of our class E common stock.
Kyle Vann, Director, joined the Board of Directors of Chaparral in November 2012 as a nominee of CCMP Capital Advisors, LLC. He joined CCMP Capital as an Executive Advisor in October 2012. Mr. Vann possesses extensive experience in midstream, energy services and trading. He spent 25 years in various senior leadership positions at Koch Industries including leading the creation of Entergy-Koch LP, an energy trading and transportation joint venture between Entergy Corporation and Koch Industries operating in North America and Europe, and served as its CEO. A chemical engineer by training, Mr. Vann has supported development of early trading models for price-setting mechanisms between crude and refined products, the development of Koch’s Texas Pipeline System from Corpus Christi, Texas, to Dallas, and was also deeply involved with Charles Koch’s development of Market-Based Management® which helped the company significantly out-perform the S&P 500. Mr. Vann started his career with Humble Oil and Refining Company (which later became part of Exxon) as a refinery engineer. He also serves on the board of directors of Texon LP, Enlink Midstream LP, Legacy Reserves LP and Eco Services and provides energy consulting services to Entergy Corporation. He earned his B.S. in Chemical Engineering from the University of Kansas and recently was named as a recipient of the university’s Distinguished Engineering Service Award. Mr. Vann is one of the two board designees of the holders of our class E common stock.
Board Committees
On April 12, 2010, our Board of Directors established a compensation committee and an audit committee, effective upon the closing of the sale of our common stock to CCMP. All members of the Board of Directors were appointed to both the compensation committee and the audit committee, and the Board of Directors adopted charters for both committees on November 10, 2010. Christopher Behrens is Chairman of the audit and compensation committees.
Code of Ethics
We have adopted a Code of Business Conduct and Ethics that is applicable to all employees, officers and members of our board of directors. The Code of Business Conduct and Ethics is available on our website at http://www.chaparralenergy.com.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
COMPENSATION DISCUSSION AND ANALYSIS
Overview & Oversight of Compensation Program
Our compensation programs include programs that are designed specifically for our most senior executive officers (“Senior Executives”), which includes our Principal Executive Officer (“PEO”) and the other executive officers named in the Summary Compensation Table (the “Named Executive Officers” or “NEOs”). Currently, our PEO and board of directors oversee the compensation programs for our Senior Executives.
Overview of Compensation Philosophy and Program
In order to recruit and retain the most qualified and competent individuals as Senior Executives, we strive to maintain a compensation program that is competitive in the labor market. The following compensation objectives are considered in setting the compensation programs for our Senior Executives:
•
drive and reward performance which supports our core values;
•
align the interests of Senior Executives with those of stockholders;
•
design competitive total compensation and rewards programs to enhance our ability to attract and retain knowledgeable and experienced Senior Executives; and
•
set compensation and incentive levels that reflect mid-range market practices.
Compensation Targets
From time to time, we review compensation data from a variety of different sources, including from the Oil & Gas E&P Survey prepared by Effective Compensation, Incorporated (the “Survey Data”) to ensure that our Senior Executive base salary compensation program generally aligns with the median of the Survey Data. The Survey Data is a compilation of compensation and other data from the prior year based upon over 100 exploration and production firms that participated in the survey. In specific preparation for 2014, we utilized guidance and executive compensation data from the Southwest Energy Group and Meridian Compensation Partners.
In determining base salaries for our executive officers, in addition to the Survey Data referenced above, our Board also considers the current level of the executive officer’s compensation, both internally and relative to other Company officers and current industry and economic factors. The process can best be described as (i) first, looking within our Company at the current salary structure among the executive group to ensure fairness and consistency, (ii) second, evaluating the Company’s performance to ensure that compensation is, in large part, performance-based, (iii) third, looking at general industry conditions, and (iv) fourth, looking at peer group companies to determine if the range of compensation paid to our executive officers is within the “fairway” of the compensation paid to executives in similarly situated companies.
Compensation Elements and Rationale for Pay Mix Decisions
We believe that a competitive compensation program will enhance our ability to attract and retain Senior Executives. To reward both short- and long-term performance in our compensation program and in furtherance of our compensation objectives noted above, our executive compensation philosophy includes the following four principles:
(i) Compensation levels should be competitive
We review the Survey Data to ensure that the base salary compensation is aligned with median levels.
(ii) Compensation should be related to performance
We believe that a significant portion of a Senior Executive’s compensation should be tied to individual performance and to our overall performance measured primarily by growth in reserves, production and earnings.
(iii) Variable compensation should represent a portion of a Senior Executive’s total compensation
We intend for a portion of compensation paid to Senior Executives to be variable in order to: 1) allow flexibility when our performance and/or industry conditions are not optimum; 2) maintain the ability to reward Senior Executives for our overall growth; and 3) retain Senior Executives when industry conditions necessitate. Senior Executives should have the incentive of increasing our profitability and value in order to earn a portion of their compensation package.
(iv) Compensation should balance short- and long-term performance
We seek to structure a balance between achieving strong short-term annual results and ensuring our long-term viability and success. To reinforce the importance of balancing these perspectives, Senior Executives are regularly provided compensation based on both the accomplishment of short-term objectives and incentives for achieving long-term objectives. While our annual bonus plans are structured to reward the accomplishment of short-term objectives, in 2004, we began a long-term compensation plan for our executive employees and other key employees. This plan is to deliver long-term incentive awards aligned with the interests of stockholders while simultaneously serving as a retention tool.
Review of Senior Executive Performance
The PEO reviews, on an annual basis, each compensation element of a Senior Executive. In each case, the PEO takes into account the scope of responsibilities and experience, succession potential, strengths and weaknesses, and contribution and performance over the past year and balances these against competitive salary levels. The PEO works daily with the Senior Executives, which allows him to form his assessment of each individual’s performance. The PEO’s performance is assessed by the Board, taking into account the scope of responsibilities and experience, strengths and weaknesses, and contributions and performance over the past year balanced against competitive salary levels.
Components of the Executive Compensation Program
We believe the total compensation and benefits program for Senior Executives should consist of the following:
•
base salaries;
•
annual bonus plans;
•
long-term retention and incentive compensation; and
•
health and welfare benefits and retirement.
Base Salaries
For 2014, Senior Executive base salaries were increased from 2013 (on average eight percent (8%)) due to general industry conditions and the economic and industry outlook for 2014. We usually adjust base salaries for Senior Executives annually based on performance. The PEO did not rely solely on predetermined formulas or a limited set of criteria when evaluating the base salaries of the Senior Executives for 2014. This is in line with our philosophy that Senior Executive compensation should be paid at approximately the competitive median levels based on market data, and taking current industry and economic factors into consideration. The salaries paid to the PEO and the NEOs during fiscal year 2014 are shown in the Summary Compensation Table in this annual report.
Annual Bonus Plan
In 2011, we created a non-binding, discretionary incentive program called the Annual Incentive Measure Bonus Program (the “AIM” program) which pays cash bonus awards to eligible employees when the Company achieves certain performance measures on a Company-wide basis. Amounts payable under the AIM program are tied to the approved Company budget and to certain individual, departmental, and business unit measures, including, but not limited to, employees who reach individual performance goals and contribute positively to their respective business units and the Company’s goals and objectives.
The targets for individual awards are expressed as a percentage of an employee’s eligible earnings for the plan year and are based on pay grade and level of responsibility. The first 50% of the computation of an employee’s AIM award is determined based solely on the Company’s performance on eight Company-wide performance measures: EBITDA-25%; Production Volume (Boe/d)-20%; Reserve Replacement-10%; Drilling and Completion Capital Effectiveness-15%; EOR Capital-5%; EOR Production Uplift-5%; Lease Operating Expenses ($/Boe)-10%; and Safety-10%. The remaining 50% of the computation of an employee’s AIM award is discretionary and is based on the performance of the department or business unit in which the employee works and his or her individual performance and contributions, as reflected by his or her performance review.
For the 2014 AIM program plan year, the Company performed at 64% of its target. Therefore, 50% of all eligible employees’ target bonus was paid at 64% of target. The remaining 50% was discretionary and varied by employee based on individual contributions.
2010 Equity Incentive Plan
We adopted the Chaparral Energy, Inc. 2010 Equity Incentive Plan (the “2010 Plan”) in April 2010. The 2010 Plan reserves a total of 86,301 shares of our class A common stock for awards issued under the 2010 Plan. If any award is exercised, paid, forfeited, terminated or canceled without the delivery of shares, then the shares covered by such award will be available again for grant under the 2010 Plan. All of our or our affiliates’ employees, officers, directors, and consultants, as defined in the 2010 Plan, are eligible to participate in the 2010 Plan.
Purpose
The 2010 Plan is intended to aid us in recruiting and retaining employees, officers, directors, and consultants capable of assuring our future success. We expect that the awards of stock-based compensation under the 2010 Plan and opportunities for stock ownership in the Company will provide incentives to participants to exert their best efforts for our success and also align their interests with those of our stockholders.
Administration
The 2010 Plan is administered by our Compensation Committee. Subject to the terms of the 2010 Plan, the Compensation Committee has the full power and authority to, among other things: (i) designate participants in the 2010 Plan; (ii) determine the type or types of awards to be granted to a participant; (iii) determine the number of shares to be covered by, or with respect to which payments, rights, or other matters are to be calculated in connection with, awards; (iv) determine the terms and conditions of any award; (v) determine whether, to what extent, and under what circumstances awards may be settled or exercised in cash, shares, other securities, other awards or other property, or canceled, forfeited, or suspended and the method or methods by which awards may be settled, exercised, canceled, forfeited, or suspended; (vi) interpret and administer the 2010 Plan or any award agreement issued under the 2010 Plan; (vii) establish, amend, suspend, or waive such rules and regulations and appoint such agents as it shall deem appropriate for the proper administration of the 2010 Plan; (viii) determine the fair market value of any shares issued under the 2010 Plan; (ix) prescribe the form of each award agreement, which need not be identical for each participant; and (x) make any other determination and take any other action that the Compensation Committee deems necessary or desirable for the administration of the 2010 Plan.
Types of Awards
The 2010 Plan authorizes the following types of awards:
•
Stock Options. The grant of either non-qualified or incentive stock options (“ISOs”) to purchase shares of our class A common stock are permitted under the 2010 Plan. ISOs are intended to qualify for favorable tax treatment under the Internal Revenue Code to participants in the 2010 Plan. The stock options will provide for the right to purchase shares of our class A common stock at a specified price and will become exercisable after the grant date under the terms established by the Compensation Committee. In general, the per share option exercise price may not be less than 100% of the fair market value of a share of class A common stock on the grant date. No person owning more than 10% of the total combined voting power of the Company may be granted ISOs unless (i) the option exercise price is at least 110% of the fair market value of a share of class A common stock on the grant date and (ii) the term during which such ISO may be exercised does not exceed five years from the date of grant.
•
Restricted Stock. Awards of restricted stock are permitted under the 2010 Plan, subject to any restrictions the Compensation Committee determines to impose, such as satisfaction of performance measures for a performance period, or restrictions on the right to vote or receive dividends.
•
Performance Awards. Performance awards, denominated as a cash amount (e.g., $100 per award unit) at the time of grant are permitted under the 2010 Plan. Performance awards confer on the participant the right to receive payment of such award, in whole or in part, upon the achievement of certain performance objectives during such performance periods as established by the Compensation Committee.
•
Bonus Shares. Awards of class A common stock without restrictions are permitted under the 2010 Plan, but such grants may be subject to any terms and conditions the Compensation Committee may determine.
•
Phantom Shares. Awards of phantom shares are permitted under the 2010 Plan, upon such terms and conditions as determined by the Compensation Committee. Each phantom share award shall constitute an agreement by us to issue or transfer a specified number of shares or pay an amount of cash equal to a specified number of shares, or a combination thereof to the participant in the future, subject to the fulfillment of performance objectives, if any, during the restricted period as the Compensation Committee may specify at the date of grant.
•
Cash Awards. Grants of cash awards, subject to the terms and conditions established by the Compensation Committee, are permitted under the 2010 Plan. If granted, a cash award shall be granted (simultaneously or subsequently) in tandem with another award and shall entitle a participant to receive a specified amount of cash from us upon such other award becoming taxable to the participant, which cash amount may be based on a formula relating to the anticipated taxable income associated with such other award and the payment of the cash award.
•
Other Stock-Based Awards. Grants of other types of awards that are denominated or payable in, valued in whole or in part by reference to, or otherwise based on or related to, shares of our class A common stock, subject to the terms and conditions established by the Compensation Committee, are permitted under the 2010 Plan.
Terms of Time Vested Restricted Stock Awards
Time Vested restricted stock awards generally vest with respect to twenty percent (20%) of the shares subject to the award on each of the first, second, third, fourth and fifth anniversaries of the award date, subject to the NEO remaining employed by us as of those dates.
Termination by Company Without Cause or by NEO for Good Reason. If the NEO is terminated by the Company without cause or by the NEO for good reason, then the vesting of the shares scheduled to vest during the period beginning on the date the NEO’s employment was terminated (the “Separation Date”) and ending on the 12-month anniversary of the Separation Date shall accelerate as of the Separation Date. Any shares not vested on the Separation Date will be forfeited as of the Separation Date. “Cause” and “good reason” shall have the same meanings as those terms are defined in any employment agreement then in effect between the NEO and us. See “-Potential Payments Upon Termination or Change in Control-Employment Agreements with Our NEOs” for the definitions of “cause” and “good reason.”
Accelerated Vesting Upon Certain Transactions. In the event of a transaction whereby CCMP receives cash in exchange for the sale, transfer or other disposition of its common stock pursuant to (i) a sale of the Company or (ii) an offering of its common stock to the public pursuant to a registration statement filed under the Securities Act of 1933, or any sale of its common stock thereafter (a “Transaction”), the shares held by each NEO who remains employed by us as of the date of such Transaction shall vest with respect to the fraction obtained by dividing (x) the number of shares of common stock sold pursuant to the Transaction, by (y) the 504,276 shares of class E common stock issued to CCMP on April 12, 2010 (the “Vesting Fraction”). Any shares of common stock sold pursuant to an “Excepted Transfer” are excluded from both the numerator and the denominator when determining the Vesting Fraction. “Excepted Transfer” means the transfer by CCMP and its permitted transferees of up to 20% of the common stock owned by them on or immediately following April 12, 2010. All other shares will remain subject to the normal vesting schedule.
Performance Vested Restricted Stock Awards
Performance Vested restricted stock awards vest in the event of a Transaction (i) whereby CCMP’s “net proceeds” from a Transaction yields certain target returns on investment, and (ii) the NEO remains employed by us as of the date of such Transaction. “Net proceeds” means the actual cash proceeds received by CCMP in a Transaction, but excludes the aggregate amount of out-of-pocket expenses incurred by CCMP in connection with such Transaction.
The table below sets forth the initial return-on-investment targets that triggered vesting of the Performance Vested restricted stock awards and the formula for calculating the number of shares of Performance Vested restricted stock that vest upon CCMP’s receipt of net proceeds in a Transaction.
Effective January 1, 2013, we amended and restated the Performance Vested awards to reflect that: (i) those shares which would vest if CCMP receives net cash proceeds from a Transaction that yields a return of at least 400% per share, or 20% of the Performance Vested awards then outstanding, were removed from the initial Performance Vested awards and an equal number of Time Vested shares were granted effective as of January 1, 2013; and (ii) the remaining number of Performance Vested shares outstanding were reallocated among five targets for vesting. Effective October 1, 2014, we terminated all outstanding grants of Performance Vested awards and issued new grants of Performance Vested awards to reflect that (i) a certain number of shares which would vest if CCMP receives net proceeds from a Transaction that yields a return of at least 350% per share were
removed from the initial Performance Vested awards and an equal amount were granted effective as of October 1, 2014, as Time Vested awards; and (ii) the remaining number of shares subject to the previous Performance Vested awards were reallocated among three targets for vesting. These vesting targets will apply for any new grants of Performance Vested awards. As a result of these modifications, vesting requirements for all remaining Performance Vested awards are set at the following levels:
Our Purchase Option
All Time Vested and Performance Vested restricted stock awards are subject to our right to purchase the shares that have vested under the terms of such awards, which purchase option lapses on the seventh anniversary of the grant date. If the NEO ceases his employment with us for any reason, we shall have the right to purchase the shares of restricted stock awarded to the NEO that have vested. If the NEO’s employment is terminated by us without cause, by the NEO for good reason, as a result of the NEO’s death or by the NEO without good reason, the purchase price for such shares shall be equal to the fair market value of such shares on the Separation Date. If the NEO’s employment is terminated by us for cause, the purchase price for such shares shall be $0.01 per share. In the event of the NEO’s material breach of the terms of any agreement with us that is in effect on or after the NEO’s Separation Date, other than a breach of noncompetition or nonsolicitation provisions, we may elect to purchase the shares for $0.01 per share.
Health and Welfare and Retirement Benefits
We offer a variety of health and welfare and retirement programs to all eligible employees. The Senior Executives are eligible for the same benefit programs on the same basis as the rest of our employees. The health and welfare programs are intended to protect employees against catastrophic loss and encourage a healthy lifestyle. Our health and welfare programs include medical, pharmacy, dental, life insurance, supplemental insurance policies and a flexible spending plan.
We offer a 401(k) Profit Sharing Plan that is intended to supplement the employee’s personal savings and social security. All employees, including Senior Executives, are generally eligible for the 401(k) plan. Senior Executives participate in the 401(k) plan on the same basis as other employees.
We adopted the 401(k) plan to enable employees to save for retirement through a tax-advantaged combination of employee and Company contributions and to provide employees the opportunity to directly manage their retirement plan assets through a variety of investment options. The 401(k) plan allows eligible employees to elect to contribute from 1% to 60% of their eligible compensation, up to the annual IRS dollar limit. Eligible compensation generally means all wages, salaries and fees for services paid by us. The Company matches at a rate of $1.00 per $1.00 employee contribution for the first 7% of the employee’s salary. Company contributions vest as follows:
However, regardless of the number of years of service, an employee is fully vested in his 401(k) plan if the employee retires at age 65 or later, attains age 62 and completes six years of service, or the employee’s employment is terminated due to death or total and permanent disability. The 401(k) plan provides for different investment options, for which the participant has sole discretion in determining how both the employer and employee contributions are invested. The 401(k) plan does not provide our employees the option to invest directly in our stock. The 401(k) plan offers in-service withdrawals in the form of loans, hardship distributions, after-tax account distributions and age 59.5 distributions.
Indemnification agreements
We have indemnification agreements with Mark A. Fischer, K. Earl Reynolds, Joseph O. Evans, James M. Miller, Jeffery D. Dahlberg, Dave Winchester, Charles A. Fischer, Jr., Christopher Behrens and Kyle Vann. These indemnification agreements are intended to permit indemnification to the fullest extent now or hereafter permitted by the General Corporation Law of Delaware. It is possible that the applicable law could change the degree to which indemnification is expressly permitted.
The indemnification agreements cover expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement incurred as a result of the fact that such person, in his capacity as a director or officer, is made or threatened to be made a party to any suit or proceeding. The indemnification agreements will generally cover claims relating to the fact that the indemnified party is or was an officer, director, employee or agent of us or any of our affiliates, or is or was serving at our request in such a position for another entity. The indemnification agreements will also obligate us to promptly advance all reasonable expenses incurred in connection with any claim. The indemnitee is, in turn, obligated to reimburse us for all amounts so advanced if it is later determined that the indemnitee is not entitled to indemnification. The indemnification provided under the indemnification agreements is not exclusive of any other indemnity rights; however, double payment to the indemnitee is prohibited.
We are not obligated to indemnify the indemnitee with respect to claims brought by the indemnitee against:
•
us, except for:
•
claims regarding the indemnitee’s rights under the indemnification agreement;
•
claims to enforce a right to indemnification under any statute or law; and
•
counter-claims against us in a proceeding brought by us against the indemnitee; or
•
any other person, except for claims approved by our board of directors.
We also maintain director and officer liability insurance for the benefit of each of the above indemnitees. These policies include coverage for losses for wrongful acts and omissions and to ensure our performance under the indemnification agreements. Each of the indemnitees are named as an insured under such policies and provided with the same rights and benefits as are accorded to the most favorably insured of our directors and officers.
Employment Agreements
We have entered into employment agreements with each of our NEOs, under the terms of which each will serve in their respective officerial positions. The initial term of the employment agreements are three years, each with an automatic two-year renewal and automatic annual renewals thereafter. The employment agreements provide our NEOs the following compensation arrangements:
________________
(1) The value shown is the aggregate grant date fair value computed in accordance with FASB ASC Topic 718.
Each NEO participates in our welfare benefit plans and fringe benefit, vacation and expense reimbursement policies. Each employment agreement provides for certain payments in the event of an NEO’s termination. The termination payments are discussed below under the heading “Potential Payments Upon Termination or Change of Control.” Each employment agreement contains certain restrictive covenants that generally prohibit our NEOs from (i) competing against us, (ii) disclosing information that is confidential to us and our subsidiaries and (iii) during the employment term and for each NEO, a period of months equal to the product of 12 times the Severance Multiple of that NEO, as described below, thereafter, from soliciting or hiring our employees and those of our subsidiaries or soliciting our customers.
Board of Directors Report
The board of directors has reviewed and discussed the above Compensation Discussion and Analysis with management and, based on such review and discussions, the board of directors recommended that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.
Mark A. Fischer
K. Earl Reynolds
Kyle Vann
Christopher Behrens
Charles A. Fischer
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
None of our executive officers have served as members of a compensation committee (or if no committee performs that function, the board of directors) of any other entity that has an executive officer serving as a member of our board of directors. All members of the Board of Directors serve on the compensation committee and Christopher Behrens serves as Chairman of the compensation committee.
SUMMARY COMPENSATION TABLE
The following table below summarizes the total compensation paid to or earned by each of the NEOs for the fiscal year ended December 31, 2014, 2013, and 2012.
________________
(1)
Bonuses earned by NEOs in 2014 and paid in 2015 were performance-based cash incentives under our AIM program.
(2)
The values shown are the aggregate grant date fair value for initial awards or the incremental fair value as of the modification date for modified awards, computed in accordance with FASB ASC Topic 718. As discussed above in “2010 Equity Incentive Plan - Performance Vested Restricted Stock Awards,” awards were modified in 2014 and 2013 resulting in the recognition of incremental fair value in both years.
(3)
Perquisites and other compensation are limited in scope and in 2014 were primarily comprised of company 401K matching; company automobile and airplane usage; and employer-paid medical benefits including accidental death and dismemberment, dental, life, medical and long-term and short-term disability coverage.
GRANTS OF PLAN-BASED AWARDS IN 2014
The following table shows grants of equity-based awards in 2014 for each NEO.
________________
(1)
The vesting of the Performance Vested restricted stock awards is based solely upon the rate of return obtained by CCMP from the sale of its stock. See “Executive compensation-Compensation discussion and analysis-Long-term Retention and Incentive Compensation-2010 Equity Incentive Plan-Performance Vested Restricted Stock Awards” for specific information regarding the potential vesting scenarios. The vesting scenarios do not include a target number of awards to be vested.
(2)
Initial awards of the Time Vested restricted stock awards vest over a five-year period.
(3)
The values shown are the aggregate grant date fair value for initial awards or the incremental fair value as of the modification date for modified awards, computed in accordance with FASB ASC Topic 718. As discussed above in “2010 Equity Incentive Plan - Performance Vested Restricted Stock Awards,” awards were modified in 2014 resulting in the recognition of incremental fair value.
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END 2014
The following table shows outstanding restricted stock awards as of December 31, 2014 for each NEO.
________________
(1)
Initial grants of the Time Vested restricted stock awards vest over a five-year period.
(2)
The table assumes an estimated fair value per share of $533.80 as of December 31, 2014.
(3)
See “Executive compensation-Compensation discussion and analysis-2010 Equity Incentive Plan-Performance Vested Restricted Stock Awards” for specific information regarding the potential vesting scenarios.
(4)
The table assumes an estimated fair value per share of $113.90 as of December 31, 2014.
2014 STOCK VESTED
The following table shows restricted stock awards that vested during the year ended December 31, 2014 for each NEO that participates in the 2010 Plan.
________________
(1)
In 2014, we withheld 188 vested shares to pay taxes of $158,789.
(2)
In 2014, we withheld 160 vested shares to pay taxes of $130,960.
(3)
In 2014, we withheld 168 vested shares to pay taxes of $137,508.
POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL
Employment Agreements with our NEOs
Our employment agreements with our NEOs obligate us to pay certain separation benefits to them in the event of voluntary termination, termination without cause, termination for good reason and termination in the event of disability or death. The term “disability” means the NEO’s incapacity due to physical or mental illness whereby the NEO is substantially unable to perform his duties under the employment agreement (with or without reasonable accommodation, as defined under the Americans With Disabilities Act) for a period of six (6) consecutive months. The term “cause” means termination for one of the following reasons:
•
the NEO’s conviction of, or entry by the NEO of a guilty or no contest plea to a felony or crime involving moral turpitude;
•
the NEO’s willful commission of an act of fraud or dishonesty resulting in economic or financial injury to us or any affiliate;
•
the NEO’s willful failure to substantially perform or gross neglect of his duties, including, but not limited to, the failure to follow any lawful directive of our Chief Executive Officer, within the reasonable scope of the NEO’s duties;
•
the NEO’s performance of unapproved acts materially detrimental to us or any affiliate;
•
the NEO’s use of narcotics, alcohol, or illicit drugs in a manner that has or may reasonably be expected to have a detrimental effect on his performance of his duties as our employee or on the reputation of the Company or any affiliate;
•
the NEO’s commission of a material violation of any of our rules or policies which results in injury to us; or
•
the NEO’s material breach of the employment agreement.
In Mr. Fischer’s case, the term “cause” also includes:
•
the occurrence or existence of any event constituting “Cause,” with respect to Mr. Fischer under our Second Amended and Restated Certificate of Incorporation, as amended and restated on April 12, 2010; (the “Certificate of Incorporation”);
•
a material breach by us of Article 7 of the Certificate of Incorporation caused by specific acts or omissions of Mr. Fischer, provided that we fail to remedy such breach within 90 days after we have knowledge of the initial existence of such breach; or
•
a material breach by Fischer Investments, L.L.C. of that certain Stockholders’ Agreement dated April 12, 2010.
The term “good reason” means the occurrence, without the written consent of the NEO, of one of the events set forth below:
•
a material diminution in the NEO’s authority, duties or responsibilities, combined with a demotion in the NEO’s pay grade ranking;
•
the reduction by us of the NEO’s base salary by more than 10% (unless done so for all of our executive officers);
•
the requirement that the NEO be based at any office or location that is more than 50 miles from our principal executive offices, except for travel reasonably required in the performance of the NEO’s responsibilities; or
•
any other action or inaction that constitutes a material breach by us under the employment agreement.
The term “change in control” means:
•
the consummation of any transaction or series of related transactions involving the sale of our outstanding securities (but excluding a public offering of our capital stock) for securities or other consideration issued or paid or caused to be issued or paid by such other corporation or an affiliate thereof and which results in our shareholders (or their affiliates) immediately prior to such transaction not holding at least a majority of the voting power of the surviving or continuing entity following such transaction; or
•
the consummation by us (whether directly involving us or indirectly involving us through one or more intermediaries) of (x) a merger, consolidation, reorganization, or business combination or (y) a sale or other disposition of all or substantially all of our assets or (z) the acquisition of assets or stock of another entity, in each case, other than a transaction which results in our voting securities outstanding immediately before the transaction continuing to represent (either by remaining outstanding or by being converted into our voting securities or the person that, as a result of the transaction, controls, directly or indirectly, us or owns, directly or indirectly, all or substantially all of our assets or otherwise succeeds to our business), directly or indirectly, at least a majority of the combined voting power of the successor entity’s outstanding voting securities immediately after the transaction.
Payments Made Upon Termination Without Cause or by the NEO for Good Reason Not Following a Change in Control
In the event an NEO’s employment is terminated without cause or by the NEO for good reason at any time that is not within two years after the occurrence of a change in control, we will be obligated:
•
to pay to the NEO an amount equal to the Severance Multiple, as specified in the NEO’s employment agreement, times the sum of (x) the NEO’s base salary in effect on the date of termination plus (y) the annual bonus granted to the NEO for the fiscal year immediately on or preceding the date of termination, payable in the form of a salary continuation for a period of months equal to the product of 12 times the Severance Multiple;
•
subject to certain limitations, to maintain for a period of 18 months following the date of termination, participation by the NEO (and his spouse and/or eligible dependents, as applicable) in our medical, hospitalization, and dental programs maintained for the benefit of our senior executive officers as in effect on the date of termination, at such level and terms and conditions (including, without limitation, contributions required by the NEO for such benefits) as in effect on the date of termination (the “Termination Welfare Benefits”);
•
to pay to the NEO any earned but unpaid base salary, annual bonus from prior years, and vacation pay in the form of a lump sum payment; and
•
to pay to the NEO any unreimbursed reasonable business expenses incurred by the NEO on our behalf in the form of a lump sum payment.
The following table quantifies amounts that would have been paid pursuant to the employment agreements for each of our NEOs assuming a termination without cause or by the NEO for good reason not following a change in control took place on December 31, 2014, and assuming all accrued compensation and reimbursable expenses had been paid on December 31, 2014.
Payments Made Upon Termination Without Cause or by the NEO for Good Reason Following a Change in Control
If at any time within two years after a change in control (“CiC”), the NEO’s employment is terminated without cause or by the NEO for good reason, we will be obligated:
•
to pay to the NEO an amount equal to the CiC Severance Multiple, as specified in the NEO’s employment agreement, times the sum of (x) the NEO’s base salary in effect on the date of termination plus (y) the annual bonus granted to the NEO for the fiscal year immediately on or preceding the date of termination, payable in the form of a salary continuation for a period of months equal to the product of 12 times the CiC Multiple, or in the form of a lump sum payment if the CiC occurs as a result of the sale or other disposition of all or substantially all of the Company’s assets;
•
subject to certain limitations, to provide the Termination Welfare Benefits;
•
to pay to the NEO any earned but unpaid base salary, annual bonus from prior years and vacation pay in the form of a lump sum payment; and
•
to pay to the NEO any unreimbursed reasonable business expenses incurred by the NEO on our behalf in the form of a lump sum payment.
The following table quantifies amounts that would have been paid pursuant to the employment agreements for each of our NEOs assuming a termination without cause or by the NEO for good reason following a CiC took place on December 31, 2014, and assuming all accrued compensation and reimbursable expenses had been paid on December 31, 2014.
Payments Made Upon Termination for Cause or by the NEO Without Good Reason
In the event an NEO is terminated for cause, or the NEO resigns without good reason, we have no further obligations to the NEO other than a lump sum payment of the following amounts:
•
any earned but unpaid base salary, annual bonus from prior years and vacation pay; and
•
unreimbursed reasonable business expenses incurred by the NEO on our behalf, so long as the NEO was not fired for cause due to his misappropriation of Company funds.
No amounts would have been paid pursuant to the employment agreements for each of our NEOs assuming a termination for cause or by the NEO without good reason took place on December 31, 2014, and assuming all accrued compensation and reimbursable expenses had been paid on December 31, 2014.
Payments Made Upon Death or Disability
In the event of an NEO’s death or disability, we will be obligated to pay to the NEO:
•
any earned but unpaid base salary, annual bonus from prior years and vacation pay;
•
unreimbursed reasonable business expenses incurred by the NEO on our behalf; and
•
a pro rata share of the annual bonus for the fiscal year in which the termination of employment occurs.
No amounts would have been paid pursuant to the employment agreements for each of our NEOs assuming an event of death or disability took place on December 31, 2014, and assuming all accrued compensation or reimbursable expenses had been paid on December 31, 2014.
Payments of separation benefits may be delayed if (i) the NEO is a “specified employee” within the meaning of Section 409A of the Internal Revenue Code of 1986, as amended (“Section 409A”), as of the date of his separation from service and (ii) the amount of any separation benefits payable to him are subject to Section 409A. In such instance, the separation benefits will not be paid to the NEO until six months after the date of separation from service, or, if earlier, the date of his death.
Other Payments Made Upon Termination, Retirement, Death or Disability
Certain accelerated vesting provisions will apply to each NEO’s restricted stock awards if the NEO’s employment is terminated without cause or by the NEO for good reason. See “-Compensation Discussion and Analysis-Long-term Retention and Incentive Compensation-2010 Equity Incentive Plan.”
Regardless of the manner in which an NEO’s employment is terminated, he is entitled to receive amounts earned during his term of employment, including unused vacation pay and bonuses earned but not yet paid under the Annual Officers Bonus. All amounts earned by our NEOs under the AIM program were paid on March 15, 2015.
Additionally, if an NEO is terminated due to death or disability, that NEO will receive benefits under our disability plan or payments under our life insurance plan.
DIRECTOR COMPENSATION
Members of our Board of Directors do not receive compensation for their services as board members. We do, however, reimburse our directors for all reasonable out-of-pocket costs and expenses incurred by them in connection with their service as a director.
COMPENSATION POLICIES AND RISK MANAGEMENT
While our Board strives to create incentives that encourage a level of risk-taking behavior consistent with our business strategy, our compensation policies and practices do not create risks that are reasonably likely to have a material adverse affect on our operations or financial condition.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Principal Stockholders
The following table sets forth information, as of March 31, 2015, with respect to all persons who own of record or are known by us to own beneficially more than 5% of our outstanding common stock, each director, and each of the Named Executive Officers, and by all directors and executive officers as a group.
________________
*
Less than 1%
(1)
The address of the stockholder is in care of Chaparral Energy, Inc., 701 Cedar Lake Boulevard, Oklahoma City, Oklahoma 73114.
(2)
Fischer Investments, L.L.C., which is owned 50% by Mark A. Fischer 1994 Trust, for which Mark A. Fischer serves as Trustee, and 50% by Susan L. Fischer 1994 Trust, for which Susan L. Fischer, the spouse of Mark A. Fischer, serves as trustee, is the record owner of these shares of our common stock with the exception of 15,103 shares held by Mark A. Fischer and 3,030 shares held by the irrevocable trusts of his children.
(3)
Charles A. Fischer, Jr., one of our directors, is one of Altoma's four managing general partners and beneficially owns a 23.15% general partner interest (including 0.90% owned by his spouse) in Altoma Energy G.P. The other partners of Altoma Energy G.P. who are each managing general partners and beneficially own in excess of 5% of its general partner interests are: Kenneth H. McCourt-36.75%; Ronald D. Jakimchuck-17.86%; and Gary H. Klassen-12.80%.
(4)
Includes all 209,882 shares owned of record by Altoma Energy G.P. Charles A. Fischer, Jr. serves as one of four managing partners of Altoma Energy G.P. Charles A. Fischer, Jr. owns directly a 22.25% general partner interest and his spouse owns directly a 0.90% general partner interest in Altoma Energy G.P.
(5)
CCMP Capital Investors II (AV-2), L.P. (“AV-2”), which owns 386,750 shares of Class E common stock and 1 share of Class F common, is part of an affiliated group of our stockholders ultimately controlled by CCMP Capital, LLC (“CCMP Capital”). The affiliated group also includes CCMP Energy I, Ltd. (“CCMP Energy”), which is wholly owned by CCMP Capital Investors II (AV-1), L.P. (“AV-1”) and which owns 58,217 shares of Class E common stock, and CCMP Capital Investors (Cayman) II, L.P. (“CCMP Cayman”), which owns 59,309 shares of Class E common stock. We refer to CCMP Cayman, AV-2 and AV-1 as the “CCMP Capital Funds”. The affiliated group controlled by CCMP Capital owns an aggregate of 504,277, or 35.7%, of our common shares outstanding as of March 31, 2015.
The general partner of the CCMP Capital Funds is CCMP Capital Associates, L.P. (“CCMP Capital Associates”). The general partner of CCMP Capital Associates is CCMP Capital Associates GP, LLC (“CCMP Capital Associates GP”). CCMP Capital Associates GP is wholly owned by CCMP Capital. CCMP Capital ultimately exercises voting and dispositive power over the shares held directly or indirectly by the CCMP Capital Funds.
Christopher Behrens is a Managing Director of CCMP Capital Advisors, LLC, an investment advisor which is wholly owned by CCMP Capital. Kyle Vann is an Executive Advisor of CCMP Capital Advisors, LLC. The address of Mr. Behrens, Mr. Vann and of each of the CCMP entities described above (other than CCMP Energy and CCMP Cayman) is c/o CCMP Capital, LLC, 245 Park Avenue, New York, NY 10167. The address of CCMP Energy and CCMP Cayman is c/o Walkers SPV Limited, PO Box 908 GT, Walker House, George Town, Grand Cayman, Cayman Islands.
(6)
Healthcare of Ontario Pension Plan Trust Fund purchased 280,000 shares of Class A stock converted from Class D and Class G stock held by CHK Energy Holdings, Inc. (CHK Energy Holdings”) effective January 14, 2014, and the remainder was purchased from various other stockholders effective January 14, 2014. The address of the stockholder is 1 Toronto Street, Suite 1400, Toronto, Ontario M5C 3B2.
(7)
Ownership of the Class A common stock is pursuant to restricted stock grants under our 2010 Plan. When granted, the Class A common stock related to these grants may vote, but remain subject to vesting in accordance with the 2010 Plan.()(
Securities Presently Authorized for Issuance under Our 2010 Plan
The following table provides information for all equity compensation plans as of December 31, 2014, under which our equity securities were authorized for issuance:
________________
(1)
This number reflects shares available for issuance under our 2010 plan. In addition, shares related to grants that are terminated, canceled, expire unexercised, or settled in such manner that all or some of the shares are not issued to a participant or are surrendered unvested shall immediately become available for issuance.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Transactions with Related Persons, Promoters and Certain Control Persons
Stockholders Agreement
CCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively “CCMP”), we, CHK Energy Holdings, Inc., Altoma Energy GP (“Altoma”), and Fischer Investments, L.L.C. (“Fischer”) entered into a Stockholders Agreement on April 12, 2010 (the “Original Date”), the closing date of the private sale of our common stock to CCMP. The Stockholders Agreement provides for certain general rights and restrictions, including board observer rights, informational rights, general restrictions on transfer of common stock, tag-along rights, preemptive rights, registration rights following a Qualified IPO (as defined in the Stockholders Agreement) and, subject to certain limited exceptions, prohibitions on the sale or acquisition of our common stock that would result in a change of control, as such term is defined under our indentures for our senior notes. In connection with the January 13, 2014 sale of our stock owned by CHK Energy Holdings, Inc. to Healthcare of Ontario Pension Plan Trust Fund, the Stockholders Agreement was amended and restated.
The Amended and Restated Stockholders Agreement also provides for the following stockholder-specific rights or restrictions:
•
Prior to a Qualified IPO, Altoma will not vote for the approval of (i) any merger, consolidation, conversion or a Demand IPO (as defined in the Amended and Restated Stockholders Agreement), (ii) certain amendments to our organizational documents, (iii) the sale of all or substantially all of our assets, or (iv) a termination of the business of or liquidation or dissolution of the Company, unless Fischer votes for such approval.
•
Other than pursuant to the exercise of preemptive rights, Healthcare of Ontario Pension Plan Trust Fund may not acquire more than 25% of our outstanding common stock.
•
CCMP may sell up to 20% of its common stock owned on the Original Date without restriction. Prior to a Qualified IPO and except in limited circumstances, CCMP is restricted from making further sales before the fourth anniversary of the Original Date, and any sales thereafter (but before a Qualified IPO) will be subject to certain rights of first offer provisions set forth in the Amended and Restated Stockholders Agreement (the “ROFO provisions”).
•
Fischer may sell up to 20% of its common stock owned immediately prior to the Original Date subject to certain restrictions. Prior to a Qualified IPO and except in limited circumstances, Fischer is restricted from making further sales before the fourth anniversary of the Original Date, and any sales thereafter (but before a Qualified IPO) will be subject to the ROFO provisions.
•
Altoma may request to transfer its shares pursuant to a demand registration, but only after Altoma first offers such shares to the Company, Fischer and CCMP in accordance with the procedures set forth in the Amended and Restated Stockholders Agreement.
•
Either (i) CCMP or (ii ) a majority in interest of Fischer and Altoma may demand that we engage in a Qualified IPO if (a) the price per share to be received by the Company or such party or parties, as the case may be, in such Demand IPO is at least 1.75 times the price per share paid by CCMP for our common stock and (b) certain other conditions are met.
•
At any time after the four year anniversary of the Original Date, CCMP may demand a Demand IPO.
•
At any time after the sixth anniversary of the Original Date, and so long as a Qualified IPO has not yet occurred, CCMP may demand a Company Sale (as defined in the Amended and Restated Stockholders Agreement), subject to a right of first offer to purchase the Company provided to Fischer.
With the exception of registration rights, the rights and preferences of a stockholder under the Amended and Restated Stockholders Agreement will generally terminate on the earlier of (x) the closing date of a Qualified IPO or (y) the date that such holder and its permitted transferees cease to beneficially own 5% or more of the Company’s fully-diluted common stock.
Review, Approval or Ratification of Transactions with Related Persons
Our board of directors is responsible for approving all related party transactions between us and any officer or director that would potentially require disclosure. The board expects that any transactions in which related persons have a direct or indirect interest will be presented to the board for review and approval but we have no written policy in place at this time.
Director Independence
Our Board uses the independence standards under the New York Stock Exchange (“NYSE”) corporate governance rules for determining whether directors are independent. The Board has determined that Messrs. Behrens, Vann and Charles A. Fischer, Jr. are independent under these NYSE rules for purposes of service on the Board.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Independent Auditor and Fees
Grant Thornton LLP, our independent registered public accounting firm, audited our consolidated financial statements for fiscal year 2014. Grant Thornton LLP has billed us and our subsidiaries fees as set forth in the table below for (i) the audits of our 2014 and 2013 annual financial statements, reviews of quarterly financial statements, and other documents filed with the Securities and Exchange Commission and (ii) assurance and other services reasonably related to the audit or review of our financial statements.
_________
(1)
There were no fees billed in 2014 or 2013 that would constitute “Tax Fees” or “All Other Fees.”
Pre-Approved Policies and Procedures
We currently have two board committees, audit and compensation. Our board of directors has adopted policies regarding the pre-approval of auditor services. Specifically, the board of directors approves all services provided by the independent public accountants at its March meeting. All additional services must be pre-approved on a case-by-case basis. Our board of directors reviews the actual and budgeted fees for the independent public accountants periodically at regularly scheduled board meetings. All of the services provided by Grant Thornton LLP during fiscal year 2014 were approved by the board of directors.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Financial Statements, Schedules and Exhibits
(1) Financial Statements-Chaparral Energy, Inc. and Subsidiaries:
The Financial Statements listed in the Index to Consolidated Financial Statements are filed as part of this report on Form 10-K (see Part II, Item 8 - Financial Statements and Supplementary Data).
(2) Financial Statement Schedules
All other consolidated financial statement schedules have been omitted because they are not required, are not applicable, or the required information has been included elsewhere within this Form 10-K.
(3) Exhibits
________________
*
Incorporated by reference
†
Management contract or compensatory plan or arrangement
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
CHAPARRAL ENERGY, INC.
By:
/s/ Mark A. Fischer
Name:
Mark A. Fischer
Title:
Chief Executive Officer
(Principal Executive Officer)
By:
/s/ Joseph O. Evans
Name:
Joseph O. Evans
Title:
Chief Financial Officer and
Executive Vice President
(Principal Financial Officer and
Principal Accounting Officer)
Date: March 31, 2015
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
EXHIBIT INDEX
________________
*
Incorporated by reference
†
Management contract or compensatory plan or arrangement