Item 1A. Risk Factors
Our acquisition, exploitation and development projects require substantial capital expenditures. We may have difficulty financing our planned capital expenditures, which could adversely affect our business, financial condition and results of operation.
The oil and natural gas industry is capital intensive. We make, and intend to continue to make, substantial capital expenditures in our acquisition, exploitation and development projects. While we intend to finance our future capital expenditures through a variety of sources, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. Additionally, we expect that future acquisitions will require funding, at least in part, from the issuance of equity securities. We may not be able to secure additional debt financing or the additional equity financing required for acquisitions on reasonable terms or at all. Financing may not continue to be available to us under our existing or new financing arrangements. If additional capital resources are unavailable, we may be forced to curtail our drilling, development and other activities or sell some of our assets on an untimely or unfavorable basis. Any such curtailment or sale could have a material adverse effect on our business, financial condition and results of operations.
Oil and natural gas prices are volatile and we may not be able to meet our hedging goals. A substantial or extended decline in oil or natural gas prices could adversely affect our results of operations.
Our revenues, operating results and future rate of growth depend upon the prices we receive for our oil and natural gas production. Historically, the markets for oil and natural gas have been volatile and are likely to continue to be volatile in the future. Although we will seek to enter into commodity price hedging contracts for additional volumes of our expected proved developed producing production, approximately 74% and 72% of our expected 2012 and 2013 proved developed producing production, respectively, has been hedged as of December 31, 2011, based on forecasted production set forth in our most recent reserve report. We cannot assure you that we will be able to meet our goal of increasing the level of our hedges for expected proved developed producing production by any certain date or at all or that our level of hedges in 2012 and 2013 will remain the same if actual production is different from expected production. To the extent we are not hedged, we will sell our oil and natural gas at current market prices, which exposes us to the risks associated with volatile commodity prices. In addition, the prices that we receive for our oil and natural gas production generally trade at a discount to the relevant benchmark prices such as NYMEX. The difference between the benchmark price and the price we receive is called a differential. We cannot accurately predict oil and natural gas differentials.
The markets and prices for oil and natural gas depend on numerous factors beyond our control. These factors include demand for oil and natural gas, which fluctuate with changes in market and economic conditions and other factors, including:
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worldwide and domestic supplies of oil and natural gas;
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actions taken by foreign oil and natural gas producing nations;
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political conditions and events (including instability or armed conflict) in oil producing or natural gas producing regions;
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the level of global and domestic oil and natural gas inventories;
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the price and level of foreign imports including liquefied natural gas imports;
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the level of consumer demand;
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the price and availability of alternative fuels;
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the availability of pipeline or other takeaway capacity;
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weather conditions;
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technological advances affecting energy consumption;
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domestic and foreign governmental regulations and taxes; and
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the overall worldwide and domestic economic environment.
Significant declines in oil and natural gas prices for an extended period may have the following effects on our business:
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adversely affect our financial condition, liquidity, ability to finance planned capital expenditures and results of operations;
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reduce the amount of oil and natural gas that we can produce economically;
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cause us to delay or postpone some of our capital projects;
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reduce our revenues, operating income and cash flow;
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reduce the carrying value of our oil and natural gas properties; and
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limit our access to sources of capital.
Our level of indebtedness may adversely affect our cash available for operations.
As of December 31, 2011, we had approximately $381.9 million in outstanding indebtedness and had approximately $40.4 million of available borrowing capacity under our amended and restated first lien credit agreement (the “2011 Credit Facility”). Our level of indebtedness will have several important effects on our operations, including:
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we will dedicate a portion of our cash flow from operations to the payment of interest on our indebtedness and to the payment of our other current obligations and will not have that portion of cash flow available for other purposes;
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our debt agreements limit our ability to borrow additional funds or dispose of assets and may affect our flexibility in planning for, and reacting to, changes in business conditions;
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our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes may be impaired;
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we may be more vulnerable to economic downturns and our ability to withstand sustained declines in oil and natural gas prices may be impaired;
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since outstanding balances under our 2011 Credit Facility are subject to variable interest rates, we are vulnerable to increases in interest rates;
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our flexibility in planning for or reacting to changes in market conditions may be limited; and
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we may be placed at a competitive disadvantage compared to our competitors that have less indebtedness.
We have had losses in the past and there is no assurance of our profitability for the future.
We recorded a net loss for the years ended December 31, 2011, 2010 and 2009 of $23.6 million, $70.6 million and $8.6 million, respectively. We cannot assure you that our current level of operating results will continue or improve. Our activities could require additional equity or debt financing. Our future operating results may fluctuate significantly depending upon a number of factors, including industry conditions, prices of oil and natural gas, rates of production, timing of capital expenditures and drilling success. Negative changes in these variables could have a material adverse effect on our business, financial condition and results of operations.
We cannot assure you that we will be able to improve our leverage position.
A significant element of our business strategy involves improving our ratio of debt to EBITDA and the aggregate value of our assets. However, we are also seeking to acquire, exploit and develop additional reserves which may require the incurrence of additional indebtedness. Although we will seek to improve our leverage position, our ability to reduce our level of indebtedness depends on a variety of factors, including future performance. General economic conditions, oil and natural gas prices and financial, business and other factors will also affect our ability to improve our leverage position. Many of these factors are beyond our control.
Although our oil and natural gas reserve data is independently estimated, these estimates may still prove to be inaccurate.
Our proved reserve estimates are prepared each year by W.D. Von Gonten & Co., our independent consulting petroleum engineers. In conducting their evaluation, the engineers and geologists of W.D. Von Gonten & Co. evaluate our properties and independently develop proved reserve estimates. There are numerous uncertainties and risks that are inherent in estimating quantities of oil and natural gas reserves and projecting future rates of production and timing of development expenditures, and those estimates and projections are subject to many factors that are beyond our control. Factors and assumptions taken into account in our estimates and projections include:
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expected reservoir characteristics based on geological, geophysical and engineering assessments;
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future production rates based on historical performance and expected future operating and investment activities;
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future oil and natural gas prices and quality and location differentials; and
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future development and operating costs.
Although we believe the independent reserve estimates of W.D. Von Gonten & Co. are reasonable based on the information available to them at the time they prepare their estimates, our actual results could vary materially from these estimated quantities of proved oil and natural gas reserves (in the aggregate and for a particular location), production, revenues, taxes and development and operating expenditures. In addition, these estimates of net proved reserves may be subject to downward or upward revision based upon production history, results of future exploitation and development, prevailing oil and natural gas prices, operating and development costs and other factors.
Finally, recovery of proved undeveloped reserves generally requires significant capital expenditures and successful drilling operations. At December 31, 2011, approximately 39% of our estimated net proved reserves were classified as undeveloped. At December 31, 2011, we estimated that it would require additional capital expenditures of approximately $190.7 million to develop our proved undeveloped reserves. Our reserve estimates assume that we can and will make these expenditures and conduct these operations successfully, which may not occur, and as a result, we may not be able to recover or develop our proved undeveloped reserves.
Lower oil and natural gas prices may cause us to record ceiling limitation impairments, which would increase our stockholders’ deficit.
We use the full cost method of accounting for our oil and natural gas investments. Accordingly, we capitalize the cost to acquire, explore for and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized cost of oil and natural gas properties may not exceed a “ceiling limit” that is based upon the present value of estimated future net revenues from net proved reserves, discounted at 10%, plus the lower of the cost or fair market value of unproved properties and other adjustments as required by Regulation S-X under the Securities Act. If net capitalized costs of oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling limitation impairment.” The risk that we will experience a ceiling limitation impairment increases when oil and natural gas prices are depressed, if we have substantial downward revisions in estimated net proved reserves or if estimates of future development costs increase significantly. In 2009 we had a ceiling limitation impairment of approximately $39.6 million and in 2011 we had a ceiling limitation impairment of approximately $18.2 million. Although we did not have a ceiling limitation impairment in 2010, no assurance can be given that we will not experience a ceiling limitation impairment in future periods. For more information about our prior impairments, see “Management’s Discussion and Analysis of Financial Condition and Results of Operation - Critical Accounting Policies - Oil and Natural Gas Properties.”
The instrument governing our indebtedness contains significant operating and financial restrictions, which may prevent us from capitalizing on business opportunities and taking some actions.
The instruments governing our indebtedness contain customary restrictions on our activities, including covenants that restrict our and our subsidiaries’ ability to:
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incur additional indebtedness;
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pay dividends on, redeem or repurchase stock;
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create liens;
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make specified types of investments;
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apply net proceeds from certain asset sales;
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engage in transactions with our affiliates;
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engage in sale and leaseback transactions;
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merge or consolidate;
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restrict dividends or other payments from subsidiaries;
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sell equity interests of subsidiaries; and
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sell, assign, transfer, lease, convey or dispose of assets.
The indenture governing our 10.500% Senior Secured Second Lien Notes due 2016 (the “Notes”) contains certain incurrence-based covenants that limit our ability to incur indebtedness and engage in other transactions. One of these covenants incorporates the net present value of our net proved reserves calculated based on SEC rules. Our ability to increase our borrowings in 2012 will depend, in part, on prices for oil and natural gas and our drilling results at the time of redetermination. Our 2011 Credit Facility also requires us to meet a minimum current ratio, a minimum interest coverage ratio and leverage ratios relating to both total debt to EBITDA and total senior debt to EBITDA. We may not be able to maintain or comply with these ratios, and if we fail to be in compliance with these covenants, we will not be able to borrow funds under our 2011 Credit Facility, which would make it difficult for us to operate our business.
The restrictions in the instruments governing our indebtedness may prevent us from taking actions that we believe would be in the best interest of our business, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. We may also incur future indebtedness obligations that might subject us to additional restrictive covenants that could affect our financial and operational flexibility. We cannot assure you that we will be granted waivers or amendments to these agreements if for any reason we are unable to comply with these agreements or that we will be able to refinance our indebtedness on terms acceptable to us, or at all.
The breach of any of these covenants and restrictions could result in a default under the instruments governing our indebtedness. An event of default under our debt agreements would permit some of our lenders to declare all amounts borrowed from them to be due and payable. If we are unable to repay such indebtedness, lenders having secured obligations could exercise their rights and remedies against the collateral securing the indebtedness. Because the indenture governing the Notes and the agreements governing our 2011 Credit Facility have customary cross-default provisions, if the indebtedness under either or any future facilities is accelerated, we may be unable to repay or refinance the amounts due.
We expect that it will be necessary to raise equity capital in order to finance most of our acquisitions. An inability to raise equity capital would limit our ability to acquire additional reserves.
As a result of our existing levels of indebtedness, we expect that it will be necessary to fund future acquisitions, at least in part, with the net proceeds of equity financings. Our ability to obtain equity financing will depend, among other things, on our level of success with our exploitation and development activities and general conditions in the capital markets at the time funding is sought. We may not be able to secure equity financing on reasonable terms or at all. If additional capital resources are unavailable, we may not be able to pursue acquisitions of additional reserves or otherwise execute our business strategy.
We may incur additional indebtedness, which could further exacerbate the risks associated with our substantial leverage.
We may incur substantial additional indebtedness in the future. The indenture governing the Notes and the agreements governing our 2011 Credit Facility contain restrictions on our ability to incur indebtedness. These restrictions, however, are subject to a number of qualifications and exceptions, and under certain circumstances we could incur substantial additional indebtedness in compliance with these restrictions. Moreover, these restrictions will not prevent us from incurring obligations that do not constitute “Indebtedness” under the indenture and the 2011 Credit Facility, respectively. If we incur indebtedness above our current levels, the related risks that we now face could intensify and we may not be able to meet all our debt obligations. Failure to meet these obligations could result in a default under our debt agreements, which could adversely affect our business, financial condition and results of operations.
Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our cash flows and our ability to raise capital.
The current reserve to production ratio of our properties is 12.9 years. As a result, unless we conduct successful development and exploitation activities or acquire properties containing net proved reserves, our net proved reserves will decline as those reserves are produced. Producing oil and natural gas are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. In particular, approximately 50% of our total net proved reserves and approximately 64% of our total production were in our Texas Gulf Coast and Southeast areas. Reservoirs in our Texas Gulf Coast and Southeast areas are characterized by high initial production rates followed by steep declines in production, resulting in a reserve life for wells in this area that is shorter than the industry average. Our future oil and natural gas reserves and production, and therefore our cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. If we are unsuccessful in acquiring or developing additional producing reserves, our production and revenues will decline as our current reserves are depleted. We cannot assure you that we will be able to develop, exploit, find or acquire additional reserves sufficient to replace our current and future production on an economic basis or at all.
Economic uncertainty could negatively impact the prices for oil and natural gas, limit access to the credit and equity markets, increase the cost of capital, and may have other negative consequences that we cannot predict.
Economic uncertainty in the United States, Europe and Asia could create financial challenges if conditions do not improve. Standard & Poor’s downgraded the U.S. credit rating to AA+ from its top rank of AAA and more recently has downgraded the credit ratings for several countries in Europe, which has increased the possibility of other credit-rating agency downgrades which could have a material adverse effect on the financial markets and economic conditions in the United States and throughout the world. Our internally generated cash flow and cash on hand historically have not been sufficient to fund all of our expenditures, and we have relied on, among other things, bank financings and private equity to provide us with additional capital. Our ability to access capital may be restricted at a time when we would like, or need, to raise capital. If our cash flow from operations is less than anticipated and our access to capital is restricted, we may be required to reduce our operating and capital budget, which could have a material adverse effect on our results and future operations. Ongoing uncertainty may also reduce the values we are able to realize in asset sales or other transactions we may engage in to raise capital, thus making these transactions more difficult and less economic to consummate. Additionally, demand for oil and natural gas may deteriorate and result in lower prices for oil and natural gas, which could have a negative impact on our revenues. Lower prices could also adversely affect the collectability of our trade receivables and cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations.
Failure to generate sufficient cash to service our indebtedness could adversely affect our business, financial condition and results of operations.
Our ability to meet our indebtedness obligations and other expenses will depend on our future performance, which will be subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under our 2011 Credit Facility or otherwise in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. Failure to generate sufficient cash to service our indebtedness could adversely affect our business, financial condition and results of operations.
If we are unable to meet our debt service obligations, we may be required to seek a waiver or amendment from our debt holders, refinance such debt obligations or sell assets or additional equity. We may not be able to obtain such financing or complete such transactions on terms acceptable to us, or at all. Failure to meet our debt obligations could result in a default under our debt agreements. An event of default under our debt agreements will permit some of our lenders to declare all amounts borrowed from them to be due and payable. If we are unable to repay such indebtedness, lenders having secured obligations could proceed against the collateral securing the indebtedness. Because the indenture governing the Notes and the agreements governing our 2011 Credit Facility have customary cross-default provisions, if the indebtedness under the Notes or under our 2011 Credit Facility is accelerated, we may be unable to repay or finance the amounts due.
We are not the operator of all of our oil and natural gas properties and therefore are not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties.
We currently operate approximately 56.9% of our properties, based on producing wells at December 31, 2011. As a result, we may have limited ability to exercise influence over the operations of some non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:
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the timing and amount of capital expenditures;
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the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;
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the operator’s expertise and financial resources;
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approval of other participants in drilling wells;
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selection of technology; and
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the rate of production of the reserves.
In addition, when we are not the majority owner or operator of a particular oil or natural gas project, if we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited.
Our hedging activities may prevent us from benefiting from price increases and may expose us to other risks.
In an attempt to reduce our sensitivity to energy price volatility and in particular to downward price movements, we enter into hedging arrangements with respect to a portion of our expected production, such as the use of derivative contracts that generally result in a range of minimum and maximum price limits or a fixed price over a specified time period. Even if we are successful in our strategy to increase our hedging activities, such activities may expose us to the risk of financial loss in certain circumstances. For example, if we do not produce our oil and natural gas reserves at rates equivalent to our derivative position, we would be required to satisfy our obligations under those derivative contracts on potentially unfavorable terms without the ability to offset that risk through sales of comparable quantities of our own production. Additionally, because the terms of our derivative contracts are based on assumptions and estimates of numerous factors such as cost of production and pipeline and other transportation and marketing costs to delivery points, substantial differences between the prices we receive pursuant to our derivative contracts and our actual results could harm our anticipated profit margins and our ability to manage the risk associated with fluctuations in oil and natural gas prices. We also could be financially harmed if the counterparties to our derivative contracts prove unable or unwilling to perform their obligations under such contracts. Additionally, before our 2010 recapitalization (as described below under “Management’s Discussion and Analysis of Financial Condition and Results of Operation - Overview”), some of our derivative contracts required us to deliver cash collateral or other assurances of performance to the counterparties if our payment obligations exceeded certain levels. No cash collateral requirements characterize our current liability hedging positions. Future collateral requirements are uncertain but will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and future rules and regulations promulgated by the Commodities Futures Trading Commission (“CFTC”), pursuant to the mandate of the United States Congress under the Dodd-Frank Wall Street Reform and Consumer Protection Act. See also “- Derivatives regulation included in current financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices.”
The lack of availability or high cost of drilling rigs, crews, equipment, supplies, insurance, personnel and oil field services could adversely affect our ability to execute our exploitation and development plans on a timely basis and within our budget.
Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, crews, equipment, supplies, insurance or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. If increasing levels of exploitation and production result in response to strong prices of oil and natural gas, the demand for oilfield services will likely rise, and the costs of these services will likely increase, while the quality of these services may suffer. If the lack of availability or high cost of drilling rigs, equipment, supplies, insurance or qualified personnel were particularly severe in our areas of operation, our results of operations could be materially and adversely affected.
We depend on our key management personnel and technical experts and the loss any of these individuals could adversely affect our business.
If we lose the services of our key management personnel or technical experts, or are unable to attract additional qualified personnel, our business, financial condition, results of operations, development efforts and ability to grow could be adversely affected. We depend upon the knowledge, skill and experience of these experts to assist us in improving the performance and reducing the risks associated with our participation in oil and natural gas exploitation and development projects. The loss of the services of one or more members of our senior management or technical teams could have a negative effect on our business, financial condition, results of operations and future growth.
Our properties are located in regions which make us vulnerable to risks associated with operating in one major contiguous geographic area, including the risk and related costs of damage or business interruptions from hurricanes.
Our properties are primarily located onshore and in state and federal waters along the Texas and Louisiana Gulf Coast region of the United States. As a result of this geographic concentration, we are disproportionately affected by any delays or interruptions in production or transportation in these areas caused by governmental regulation, transportation capacity constraints, natural disasters, regional price fluctuations and other factors. This is particularly true of our inland water drilling and offshore operations, which are susceptible to hurricanes and other tropical weather disturbances. Such disturbances have in the past and will in the future have any or all of the following adverse effects on our business:
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interruptions to our operations as we suspend production in advance of an approaching storm;
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damage to our facilities and equipment, including damage that disrupts or delays our production;
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disruption to the transportation systems we rely upon to deliver our products to our customers; and
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damage to or disruption of our customers’ facilities that prevents us from taking delivery of our products.
For example, in 2008, Hurricanes Gustav and Ike disrupted our Gulf Coast operations forcing us to temporarily curtail production for approximately 30 days. Although we maintain property and casualty insurance, we cannot predict whether we will continue to be able to obtain insurance for hurricane-related damages or, if obtainable and carried, whether this insurance will be adequate to cover our liabilities. In addition, we expect any insurance of this nature to be subject to substantial deductibles and to provide for premium adjustments based on claims. Any future hurricane-related costs and work interruptions could adversely affect our operations and financial condition.
Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are extended.
Certain of our undeveloped leasehold acreage is subject to leases that will expire unless production in paying quantities is established during their primary terms or we obtain extensions of the leases. Our drilling plans for our undeveloped leasehold acreage are subject to change based upon various factors, including factors that are beyond our control, such as drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Because of these uncertainties, we do not know if our undeveloped leasehold acreage will ever be drilled or if we will be able to produce crude oil or natural gas from these or any other potential drilling locations. If our leases expire, we will lose our right to develop the related properties on this acreage. As of December 31, 2011, we had leases representing 3,207 net acres expiring in 2012, 1,912 net acres expiring in 2013, and 4,229 net acres expiring in 2014. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
Availability under our 2011 Credit Facility is based on a borrowing base that is subject to redetermination by our lenders. If our borrowing base is reduced, we may be required to post additional assets as collateral or repay amounts outstanding under our 2011 Credit Facility.
Under the terms of our 2011 Credit Facility, our borrowing base is subject to semi-annual redetermination by our lenders based on their valuation of our net proved reserves and their internal criteria. In addition to such semi-annual determinations, our lenders may request one additional borrowing base redetermination during each six-month period between borrowing base determinations. In the past, the borrowing base under our credit agreements has been reduced as a result of, among other things, changes in pricing, production, monetization of unrealized hedging gains and our disposition of assets included in the then-current borrowing base. A reduction in our borrowing base below the amount outstanding under our 2011 Credit Facility will result in a borrowing base deficiency requiring us to cure such deficiency by posting additional assets as collateral or repaying a portion of the loan under the 2011 Credit Facility over a period no longer than five months. If we do not have sufficient funds on hand for repayment, we may be required to seek a waiver or amendment from our lenders, refinance our 2011 Credit Facility or sell assets. We may not be able obtain such financing or complete such transactions on terms acceptable to us, or at all. Failure to cure a borrowing base deficiency could result in a default under our 2011 Credit Facility, which could adversely affect our business, financial condition and results of operations.
Our exploitation, development and drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns.
We require significant amounts of undeveloped leasehold acreage to further our development efforts. Exploitation, development, drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. We invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that all of our prospects will result in viable projects or that we will not abandon our initial investments. Additionally, we cannot guarantee that the leasehold acreage we acquire will be profitably developed, that new wells drilled by us in areas that we pursue will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. Wells that are profitable may not achieve our targeted rate of return. Our ability to achieve our target results is dependent upon the current and future market prices for oil and natural gas, costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost.
Although we aim to control and reduce our drilling and production costs to improve our overall return, the cost of drilling, completing and operating a well is often uncertain and cost factors can adversely affect the economics of a project. We cannot predict the cost of drilling, and we may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including:
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unexpected drilling conditions;
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low prices for oil and natural gas;
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title problems;
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pressure or irregularities in formations;
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delays by project participants;
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equipment failures or accidents;
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adverse weather conditions;
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compliance with governmental requirements;
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shortages or delays in the availability of drilling rigs and the delivery of equipment; and
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increases in the cost for equipment and services.
We may not drill all of our potential drilling locations and drilling locations that we decide to drill may not yield oil or natural gas in commercially viable quantities or quantities sufficient to meet our targeted rate of return.
Our drilling locations are in various stages of evaluation, ranging from locations that are ready to be drilled to potential locations that will require substantial additional evaluation and interpretation. A decision to drill any specific well on our inventory of potential well locations may not be made for many years, if at all. If a decision is made to drill, we cannot conclusively predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover our drilling or completion costs or to be economically viable. Our use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil and natural gas will be present or, if present, whether oil and natural gas will be present in commercial quantities.
The analysis that we perform using data from other wells, more fully explored prospects and/or analogous producing fields may not be useful in predicting the characteristics and potential reserves associated with our drilling locations. As a result, we may not find commercially viable quantities of oil and natural gas and, therefore, we may not achieve a targeted rate of return or have a positive return on investment.
The marketability of our oil and natural gas production depends on services and facilities that we typically do not own or control. The failure or inaccessibility of any such services or facilities could affect market based prices or result in a curtailment of production and revenues.
The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of oil and natural gas gathering and transportation systems, pipelines and processing facilities. We generally deliver oil at our leases under short-term trucking contracts. Counterparties to our short-term contracts rely on access to regional transportation systems and pipelines. If transportation systems or pipeline capacity is constrained, we would be required to find alternative transportation modes, which would impact the market based price that we receive, or temporarily curtail production. We generally sell our natural gas production at the wellhead. The transportation of our natural gas may be interrupted due to capacity constraints on the applicable system, for maintenance or repair of the system, or for other reasons as dictated by the particular agreements. If any of the pipelines or other facilities that we use to transport our natural gas production become unavailable, we would be required to find a suitable alternative to transport and process the natural gas, which could increase our costs and reduce the revenues we might obtain from the sale of the natural gas. For example, in 2008, Hurricanes Gustav and Ike disrupted our Gulf Coast operations forcing us to temporarily curtail production for approximately 30 days.
We are subject to various operating and other casualty risks that could result in liability exposure or the loss of production and revenues.
Our operations are subject to hazards and risks inherent in drilling for and producing and transporting oil and natural gas, such as:
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fires;
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natural disasters;
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formations with abnormal pressures;
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blowouts, mechanical failures and explosions; and
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pipeline ruptures and spills.
Any of these hazards and risks can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties and the property of others. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.
We cannot predict all liabilities and costs related to expanding our geographic diversity. The incurrence of material unanticipated liabilities could have a material adverse effect on our business, financial condition and results of operation.
We intend to grow our reserve base primarily through asset acquisitions and the further exploitation and development of acquired and existing assets, with a focus on properties that are weighted towards oil or NGLs and provide greater geographic diversity. Historically we have operated properties only in the Gulf Coast region. We cannot assure you that we will be successful in expanding our operations into regions outside of our core areas. Operating in areas outside the Gulf Coast region may expose us to unanticipated liabilities and costs, some of which may be material. As a result, the anticipated benefits of moving into the region may not be fully realized, if at all, which could have a material adverse effect on our business, financial condition and results of operation.
We rely on independent experts and technical or operational service providers over whom we may have limited control.
We use independent contractors to provide us with technical assistance and services. We rely upon the owners and operators of rigs and drilling equipment, and upon providers of field services, to drill and develop our prospects to production. In addition, we rely upon the services of other third parties to explore or analyze our prospects to determine a method in which the prospects may be developed in a cost-effective manner. Our limited control over the activities and business practices of these providers, any inability on our part to maintain satisfactory commercial relationships with them or their failure to provide quality services could materially and adversely affect our business, results of operations and financial condition.
We may be unable to successfully integrate the properties and assets we acquire with our existing operations.
Integration of the properties and assets we acquire may be a complex, time consuming and costly process. Failure to timely and successfully integrate these assets and properties with our operations may have a material adverse effect on our business, financial condition and results of operations. The difficulties of integrating these assets and properties present numerous risks, including:
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acquisitions may prove unprofitable and fail to generate anticipated cash flows;
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we may need to (i) recruit additional personnel, and we cannot be certain that any of our recruiting efforts will succeed and (ii) expand corporate infrastructure to facilitate the integration of our operations with those associated with the acquired properties, and failure to do so may lead to disruptions in our ongoing businesses or distract our management; and
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our management’s resources may be diverted from other business concerns.
We are also exposed to risks that are commonly associated with acquisitions of this type, such as unanticipated liabilities and costs, some of which may be material. As a result, the anticipated benefits of acquiring assets and properties may not be fully realized, if at all.
We may not have enough insurance to cover all of the risks we face, which could result in significant financial exposure.
We maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face. We may elect not to carry insurance if our management believes that the cost of insurance is excessive relative to the risks presented. If an event occurs that is not covered, or not fully covered, by insurance, it could harm our financial condition, results of operations and cash flows. In addition, we cannot fully insure against pollution and environmental risks.
The loss of a significant customer could in the short term have a material adverse impact on our financial results.
During 2011, ten customers collectively accounted for 70% of our oil and natural gas revenues, with Enterprise Crude Oil LLC accounting for 16% and Shell Trading (US) Company accounting for 17%. During 2010, ten customers collectively accounted for 69% of our oil and natural gas revenues, with Enterprise Crude Oil LLC accounting for 11% and Shell Trading (US) Company accounting for 19%. During 2009, ten customers collectively accounted for 70% of our oil and natural gas revenues, with Shell Trading (US) Company accounting for 16%. Although we believe that the availability of other potential purchasers would limit the effects of the loss of one or more of these customers, such a loss could in the short term have a material adverse effect on our results of operations.
Our future operating results may fluctuate and significant declines in them may limit our ability to invest in projects.
Our future operating results may fluctuate significantly depending upon a number of factors, including:
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industry conditions;
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prices of oil and natural gas;
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rates of drilling success;
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availability of capital resources;
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rates of production from completed wells; and
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the timing and amount of capital expenditures.
This variability could cause our business, financial condition and results of operations to suffer. In addition, any failure or delay in the realization of expected cash flows from operating activities could limit our ability to invest and participate in economically attractive projects.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
Borrowings under our 2011 Credit Facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on such variable rate indebtedness would increase, although the amount borrowed would remain the same, and our net income and cash available for servicing our indebtedness would decrease. A significant increase in our interest expense could adversely affect our business, financial condition and results of operations.
We face significant competition and many of our competitors have resources in excess of our available resources.
We operate in the highly competitive areas of oil and natural gas exploitation, acquisition and production. We face intense competition from a large number of independent, technology-driven companies as well as both major and other independent oil and natural gas companies in a number of areas such as:
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seeking to acquire desirable producing properties or new leases for future exploitation;
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seeking to hire professional personnel;
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seeking to acquire the equipment and expertise necessary to operate and develop those properties; and
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marketing our oil and natural gas production.
Many of our competitors have financial and other resources substantially in excess of those available to us. This highly competitive environment could harm our business.
We are subject to various governmental regulations and environmental risks that may cause us to incur substantial costs.
From time to time, in varying degrees, political developments and federal, state and local laws and regulations affect our operations. In particular, price controls, taxes and other laws relating to the oil and natural gas industry, changes in these laws and changes in administrative regulations have affected and in the future could affect oil and natural gas production, operations and economics. We cannot predict how agencies or courts will interpret existing laws and regulations or what effect any changes and interpretations may have on our business or financial condition. Our business is subject to laws and regulations promulgated by federal, state and local authorities, including but not limited to, the United States Congress, the Federal Energy Regulatory Commission, the EPA, the BLM, the Bureau of Ocean Energy Management, the Bureau of Safety and Environmental Enforcement, the Texas Railroad Commission, the Texas Commission on Environmental Quality, the Oklahoma Corporation Commission, the Oklahoma Department of Environmental Quality, the Louisiana Department of Natural Resources, the Louisiana Department of Environmental Quality, the Mississippi Department of Environmental Quality and the Mississippi Oil & Gas Board, relating to the exploration for, and the development, production and marketing of, oil and natural gas, as well as safety matters. Legal requirements are frequently changed and subject to interpretation and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We may be required to make significant expenditures to comply with governmental laws and regulations. The discharge of oil, natural gas or pollutants into the air, soil or water may give rise to significant liabilities to the government and third parties and may require us to incur substantial costs for remediation.
Our operations are subject to complex federal, state and local environmental laws and regulations, including the federal Comprehensive Environmental Response, Compensation and Liability Act, the Resource Conservation and Recovery Act, the Oil Pollution Act of 1990, the Clean Air Act (the “CAA”) and the Clean Water Act. Administration of the federal laws is often delegated to the states. Environmental laws and regulations are subject to change, and the implementation of new, or the modification of existing, laws or regulations could impose significant additional burdens. For example, hydraulic fracturing and associated processes, which are used in our operations to maximize oil and gas production, are undergoing increased public and regulatory scrutiny due to concerns relating to potential impact on environmental and geologic resources. These concerns are being evaluated by federal and state regulatory agencies and may result in new regulatory requirements. If new federal or state laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities, make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business. Compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the potential impact on our business that may arise if changes in requirements are imposed. It is also possible that our drilling and injection operations could adversely affect the environment, which could result in a requirement to perform investigations or clean-ups or in the incurrence of other unexpected material costs or liabilities. In addition, the EPA has recently announced its intention to develop discharge standards for wastewater produced by natural gas extraction from shale formations. Proposed rules are expected in 2014. At this time, we cannot predict the impact that these standards may have on our business.
Failure to comply with environmental, health and safety laws or regulations may result in assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and the issuance of orders enjoining or limiting our current or future operations. Compliance with these laws and regulations also increases the cost of our operations and may prevent or delay the commencement or continuance of a given operation.
Under certain environmental laws that impose strict, joint and several liability, we may be required to perform remediation on our properties to address historical conditions. In addition, claims for damages to persons, property or natural resources may result from environmental and other impacts of our operations. Moreover, new or modified environmental, health or safety laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. Therefore, the costs to comply with environmental, health, or safety laws or regulations or the liabilities incurred in connection with them could significantly and adversely affect our business, financial condition or results of operations.
We do not know how the ongoing reorganization of the BOEMRE will impact potential future regulations or enforcement that may affect our business.
On May 19, 2010, the U.S. Department of the Interior announced that it would reorganize the Minerals Management Service by dividing its offshore oil and gas responsibilities among three separate agencies. Shortly thereafter, on June 18, 2010, the Minerals Management Service was renamed the Bureau of Ocean Energy Management, Regulation and Enforcement (the “BOEMRE”). The BOEMRE currently regulates offshore operations, including engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the Outer Continental Shelf, and removal of facilities. On October 1, 2010, the first phase of reorganization took place when the revenue collection arm of the former Mineral Management Service became the Office of Natural Resources Revenue. On October 1, 2011, the U.S. Department of the Interior officially created the Bureau of Ocean Energy Management, which will have responsibility for leasing, resource evaluation and environmental studies, and the Bureau of Safety and Environmental Enforcement, which will have responsibility for field operations, including inspections, regulatory compliance, permitting and oil spill response. At this point, the BOEMRE ceased to exist. We have a non-operating interest in nine offshore fields in the Outer Continental Shelf off the coast of Louisiana which are subject to jurisdiction of these agencies. We do not know how the ongoing reorganization will impact potential future regulations or enforcement that may affect our business.
Derivatives regulation included in current financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices.
In July 2010, federal legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act ( the “Dodd-Frank Act”) was enacted. The Dodd-Frank Act provides for new statutory and regulatory requirements for derivative transactions, including oil and natural gas hedging transactions. Among other things, the Dodd-Frank Act provides for the creation of position limits for certain derivatives transactions, as well as requiring certain transactions to be cleared on exchanges for which cash collateral will be required. In November 2011, the CFTC published final rules that establish position limits for futures contracts on 28 physical commodities, including four energy commodities, and swaps, futures and options that are economically equivalent to those contracts. The rules provide an exemption for “bona fide hedging” transactions or positions, but this exemption is narrower than the exemption under existing CFTC position limit rules. The new limits generally will go into effect 60 days after the term “swap” is further defined pursuant to Section 721 of the Dodd-Frank Act. These new rules and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts or reduce the availability of derivatives. Although we believe the derivative contracts that we enter into should not be materially impacted by position limits and other regulatory requirements, the impact upon our businesses will depend on whether the derivative contracts we enter into are exempt from position limits as bona fide hedging transactions.
Depending on the rules adopted by the CFTC or similar rules that may be adopted by other regulatory bodies, we might in the future be required to provide cash collateral for our commodities hedging transactions under circumstances in which we do not currently post cash collateral. Posting of such additional cash collateral could impact liquidity and reduce our cash available for capital expenditures. A requirement to post cash collateral could therefore reduce our ability to execute hedges to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.
The adoption of climate change legislation by Congress could result in increased operating costs, create delays in our obtaining air pollution permits for new or modified facilities and result in reduced demand for the oil and natural gas we produce.
According to certain scientific studies, emissions of carbon dioxide, methane, nitrous oxide and other gases commonly known as greenhouse gases (“GHG”) may be contributing to global warming of the earth’s atmosphere and to global climate change. In response to the scientific studies, legislative and regulatory initiatives have been underway to limit GHG emissions. The U.S. Supreme Court determined that GHG emissions fall within the definition of an “air pollutant”, and in response the EPA promulgated an endangerment finding paving the way for regulation of GHG emissions under the CAA. The EPA has also promulgated rules requiring owners or operators of certain petroleum and natural gas systems that emit 25,000 metric tons or more of GHG per year from a facility to report such emissions and we are subject to this reporting requirement. In addition, the EPA promulgated rules that significantly increase the GHG emission threshold that would identify major stationary sources of GHG subject to CAA permitting programs. As currently written and based on our current operations, we are not subject to federal GHG permitting requirements. Regulation of GHG emissions is new and highly controversial, and further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact us. Further, apart from these developments, recent judicial decisions that have allowed certain tort claims alleging property damage to proceed against GHG emissions sources may increase our litigation risk for such claims. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developments on us.
Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG emitting energy sources such as coal, our products could become more desirable in a market with more stringent limitations on GHG emissions. To the extent that our products are competing with lower GHG emitting energy sources such as solar and wind, our products could become less desirable in the market with more stringent limitations on GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations. Any laws or regulations that may be adopted to restrict or reduce emissions of GHG could require us to incur increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce, depending on the applicability to our operations and the refining, processing, and use of oil and natural gas.
Our ability to use net operating losses to offset future taxable income may be subject to certain limitations.
As of December 31, 2011, we had federal net operating loss carryforwards (“NOLs”) of $42.2 million to offset future taxable income, which expire in various years beginning in 2030, which if fully utilized will result in a tax savings of $14.8 million. See Note 12- “Income Taxes” to our audited consolidated financial statements elsewhere herein for more. As a result of the evaluation of the likelihood that the deferred tax asset will not be realized, we applied a valuation allowance for this deferred tax asset along with all other deferred tax assets that are a result of normal differences in GAAP treatment and applicable tax laws. This valuation will be assessed in the future based on relevant financial data and projections. In addition, under Section 382 of the U.S. Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), a corporation that experiences a more-than 50 percent ownership change over a three-year testing period is subject to limitations on its ability to utilize its pre-change NOLs to offset future taxable income.
We must increase our staff and will incur increased costs as a result of being a reporting company.
As a result of the completion of an exchange offer in November 2011, we became subject to the Exchange Act, and as a result are required to comply with the reporting obligations of a publicly traded company. We have, and must continue to, hire additional personnel or engage third party providers to meet our obligations with respect to internal controls and disclosure requirements. We also expect to engage additional accounting resources. In addition, we anticipate that our director and officer liability insurance premiums will increase. These additional obligations and responsibilities will require us to incur significant legal, accounting and other expenses that we did not incur as a non-reporting private company.
We have identified material weaknesses in our internal control over financial reporting.
We have identified material weaknesses in our internal control over financial reporting related to inconsistent or ineffective financial statement review and preparation and insufficient financial reporting resources. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected and corrected on a timely basis.
Although we intend to take appropriate steps to remediate these material weaknesses, we cannot assure you that we will be able to do so in a timely manner, that our initiatives will prove to be successful or that additional material weaknesses will not be identified in the future. Failure to identify material weaknesses in our internal controls in a timely manner, or the identification of material weaknesses in the future, will impair our ability to record, process, summarize and report financial information accurately, timely and in accordance with SEC rules. The failure could also negatively affect the trading liquidity of our notes, cause investors to lose confidence in our reported financial information, subject us to civil and criminal investigations and penalties and adversely impact our business and financial condition.
Item 1B.
Item 1B. Unresolved Staff Comments
Not Applicable.
Item 3.
Item 3. Legal Proceedings
There are currently various suits and claims pending against us that have arisen in the ordinary course of our business, including contract disputes and title disputes. Management believes that the resolution of these suits and claims will not, individually or in the aggregate, have a material effect on our consolidated financial position, results of operations or cash flow. We record reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.
Item 4.
Item 4. Mine Safety Disclosures
Not Applicable.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
There is no established public trading market for our common stock.
Holders
As of March 29, 2012, Milagro Holdings, LLC, our parent company (“Holdings”), is the sole record holder of our common stock.
Dividends
Our 2011 Credit Facility and the indenture governing the Notes, as well as the terms of our Series A preferred stock, restrict dividend payments by us on our common stock. We presently do not plan to pay future cash dividends.
Securities Authorized for Issuance Under Equity Compensation Plans
We have no outstanding equity compensation plans under which our securities are authorized for issuance. Equity compensation plans are maintained by Holdings, our parent company.
Recent Sales of Unregistered Securities
None.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
None.
Item 6.
Item 6. Selected Financial Data
The following table presents our selected historical financial data as of and for the one month ended December 31, 2007 and for the years 2008 through 2011. The statement of operations data for each of the years ended December 31, 2009 through 2011 and the balance sheet data as of December 31, 2010 and 2011 set forth below are derived from our audited financial statements and the notes thereto included elsewhere in this document. The balance sheet data as of December 31, 2007, 2008 and 2009 and statement of operations data for the year ended December 31, 2008, set forth below are derived from our audited financial statements. The statement of operations data for the one month ended December 31, 2007 is derived from our unaudited financial records. You should read this selected financial data in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and notes thereto included elsewhere in this document.
The table below does not include selected statements of operations and balance sheet data for our predecessor as for the eleven months ended November 30, 2007. A combination of factors results in our inability to provide the 2007 selected historical financial data noted above without unreasonable effort and expense. These factors are: 1) our predecessor was not accounted for as a separate entity, subsidiary, or division by the previous owner, and as a result, the selected financial data for the predecessor for the eleven months ended November 30, 2007 was not prepared and does not exist, and 2) we did not acquire the employees of the predecessor and as such the time and expense associated with preparing the applicable selected financial data for the predecessor would be unreasonable.
(1) Includes compensation expenses attributable to the issuance of Class C membership profits interests in our parent company, Holdings, to our officers and employees. For the years ended December 31, 2011, 2010, 2009 and 2008, such expenses were zero, $1,788, $1,951 and $1,951, respectively, and for the one month ended December 31, 2007, such expenses were $163. See “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters” for more on the ownership of the Class C membership profits interests.
(2) Effective on August 1, 2009, we converted from a limited liability company to a corporation under Sub Chapter C of the Internal Revenue Code of 1986, as amended.
(3) On January 13, 2010, we entered into agreements to exchange a portion of our prior second lien debt and accrued interest for $205.5 million of our Series A preferred stock, consisting of 2,700,000 shares issued at $76.12 per share that were mandatorily redeemable in 2016. These shares were classified as a liability in the financial statements as they were mandatorily redeemable for cash.
(4) On May 11, 2011, we amended the terms of our Series A preferred stock. The amendment made the Series A preferred stock a perpetual instrument and removed the mandatory redemption. The amended Series A preferred stock is redeemable at the option of the holder in 2016, and, as a result of the amendment, the Series A preferred stock was reclassified from long-term debt to mezzanine equity.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
You should read the following discussion and analysis of our financial condition and results of operations together with our consolidated financial statements and the related notes and other financial information included elsewhere in this report. Some of the information contained in this discussion and analysis or set forth elsewhere in this report, including information with respect to our plans and strategy for our business and related financing, include forward-looking statements that involve risks and uncertainties. You should review the section entitled “Risk Factors” included elsewhere herein for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis.
Overview
We are an independent oil and gas company primarily engaged in the acquisition, exploitation, development and production of oil and natural gas reserves. We were formed as a limited liability company in 2005 with a focus on properties located onshore in the U.S. Gulf Coast. We have acquired proved producing reserves that we believe have upside potential, implemented an active drilling, workover and recompletion program and expanded our geographic diversity by moving into the Midcontinent area.
In 2010, in order to improve our liquidity and capital structure and to resolve the events resulting in forbearances under our prior first lien credit agreement and prior second lien credit agreement, we effected a recapitalization through, among other things, (i) the discharge of approximately $194.7 million of prior second lien indebtedness through the issuance of Series A preferred stock, (ii) the conversion of approximately $56.2 million of prior second lien indebtedness into indebtedness under our prior second lien PIK credit agreement, and (iii) the conversion of the remaining $30.0 million of prior second lien indebtedness to indebtedness under our existing second lien term loan agreement. In addition, as part of the recapitalization, we received $60.0 million in new capital though the funding of $25.0 million in term loans and $35.0 million delayed draw loan under our existing second lien term loan agreement.
In connection with the 2010 recapitalization, and in response to changes in the business environment, we modified our business strategy by moving away from a primary focus on exploration to a more balanced approach of acquisition, exploitation, development and lower risk exploration. Our 2011 capital budget contemplated spending approximately $32.6 million in connection with the drilling of 12 additional wells, including three development wells in the Texas Gulf Coast, three development wells in the Southeast area, one development well in the South Texas area and five wells in the Midcontinent area, and spending approximately $5.0 million in connection with the workover and recompletion of existing wells. Our 2011 capital budget also included approximately $36.0 million for acquisitions. See “-Liquidity and Capital Resources” for more on our capital expenditures.
As described in more detail below, in May 2011, we completed an offering of an aggregate of $250.0 million of the 2011 Notes. We used the proceeds of this offering, together with borrowings under our 2011 Credit Facility, to refinance substantially all of our existing indebtedness (the “2011 Refinancing”).
We intend to fund our future capital expenditures through a variety of means, including cash flow from operations, borrowings under our 2011 Credit Facility, issuances of equity and debt securities, reimbursements of prior leasing and seismic costs by third parties who participate in our projects, and the sale of interests in projects and properties.
Sources of Our Revenues
We derive our revenues from the sale of oil and natural gas that are produced from our properties. Our revenues are a function of the production volumes we sell and the prevailing market prices at the time of sale. Under the terms and conditions of our 2011 Credit Facility, we are required to hedge at least 50%, but no more than 90%, of our monthly forecasted proved developed producing (“PDP”) production by product. We are permitted to use zero-cost collars and out-right swaps with approved counterparties to meet this requirement. The approved counterparties are limited to those financial institutions that participate in the 2011 Credit Facility. As of December 31, 2011, we had the following hedged positions:
% of PDP Hedged
In order to achieve more predictable cash flows and to reduce our exposure to downward commodity price fluctuations, we utilize derivative instruments to hedge future sales prices on a portion of our oil and natural gas production. As of December 31, 2011, we had hedging contracts in place for 1,784,607 Boe from January 1, 2012, through the end of 2012, 1,315,949 Boe during 2013 and 943,337 Boe during 2014. Based on the expected production set forth in our January 1, 2012 reserve report, we have hedged approximately 71% of our forecasted 2012, 2013 and 2014 PDP production as of December 31, 2011. In 2011, we realized commodity hedging gains of approximately $16.0 million, but we expect this to be significantly less in 2012. The use of certain types of derivative instruments may prevent us from realizing the benefit of upward price movements for the portion of the production that is hedged. As of the date of this report, we have met the above stated hedging obligations.
Components of Our Cost Structure
Production Costs. Production costs represent the day-to-day costs we incur to bring hydrocarbons out of the ground and to the market, combined with the daily costs we incur to maintain our producing properties. These daily costs include lease operating expenses and taxes other than income.
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Lease operating expenses are generally composed of several components, including the cost of: labor and supervision to operate our wells and related equipment; repairs and maintenance; fluid treatment and disposal; related materials, supplies, and fuel; and insurance applicable to our wells and related facilities and equipment. Lease operating expenses also include the cost for workover expense and gathering and transportation. Lease operating expenses are driven in part by the type of commodity produced, the level of workover activity and the geographical location of the properties.
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Environmental remediation expenses are costs related to environmental remediation activity associated with our ongoing operations.
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In the U.S., there are a variety of state and federal taxes levied on the production of oil and natural gas. These are commonly grouped together and referred to as taxes other than income. The majority of our production tax expense is based on a percent of gross value realized at the wellhead at the time the production is sold or removed from the lease. As a result, our production tax expense increases when oil and natural gas prices rise.
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Historically, taxing authorities have from time to time encouraged the oil and natural gas industry to explore for new oil and natural gas reserves, or to develop high cost reserves, through reduced tax rates or tax credits. These incentives have been narrow in scope and short-lived. A number of our wells have qualified for reduced production taxes because they are high cost wells.
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Taxes other than income include production taxes and ad valorem taxes, which are imposed by local taxing authorities such as school districts, cities, and counties or boroughs. The amount of tax we pay is based on a percent of value of the property assessed or determined by the taxing authority on an annual basis. When oil and natural gas prices rise, the value of our underlying property interests increase, which results in higher ad valorem taxes.
Depreciation, Depletion and Amortization. As a full cost company, we capitalize all direct costs associated with our exploitation and development efforts, including a portion of our interest and certain general and administrative costs that are specific to exploitation and development efforts, and we apportion these costs to each unit of production sold through depletion expense. Generally, if reserve quantities are revised up or down, our depletion rate per unit of production will change inversely. When the depreciable capital cost base increases or decreases, the depletion rate will move in the same direction. Our full-cost depletion expense is driven by many factors, including certain costs spent in the exploration for and development of oil and natural gas reserves, production levels, and estimates of proved reserve quantities and future developmental costs.
Asset Retirement Accretion Expense. Asset retirement accretion expense represents the systematic, monthly accretion of future abandonment costs of tangible assets such as wells, service assets, flowlines and other facilities.
General and Administrative Expense. General and administrative expense includes payroll and benefits for our corporate staff, costs of maintaining our headquarters, managing our production and development operations and legal compliance. We capitalize general and administrative costs directly related to exploitation and development efforts.
Interest. We have relied on a series of debt financings to fund our short-term liquidity and a portion of our long-term financing needs. On December 31, 2011, we had approximately $138.0 million of LIBOR-based floating rate indebtedness outstanding under our 2011 Credit Facility. In addition, our Series A preferred stock carries a non-cash cumulative coupon of 12% per annum.
As part of the 2011 Refinancing, we issued $250 million of the Notes and entered into the 2011 Credit Facility which provides for a current borrowing base of $180 million, as of December 31, 2011. Interest on the 2011 Credit Facility is calculated based on floating rates of LIBOR and Base Rate with a sliding margin that reflects usage under the facility. The higher the usage under the 2011 Credit Facility, the higher the interest margin over the floating rate index. We expect to continue to utilize indebtedness to grow and, as a result, expect to continue to pay interest throughout the term of the Notes.
Income Taxes. We recorded no income tax benefit or expense for the year ended December 31, 2011. We increased our valuation allowance and reduced our net deferred tax assets to zero during 2011 after considering all available positive and negative evidence related to the realization of our deferred tax assets. Our assessment of the realization of our deferred tax assets has not changed and as a result, we continue to maintain a full valuation allowance for our net deferred tax assets as of December 31, 2011.
As of December 31, 2011, we had no unrecognized tax benefits. There were no significant changes to the calculation since December 31, 2011. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to March 31, 2012.
Oil and Natural Gas Reserves
Our estimated total net proved reserves of oil and natural gas as of December 31, 2011 and 2010 were as follows:
Our estimated total net proved reserves increased 2% in the period ended December 31, 2011 as compared to the same period in 2010. This increase in our estimated net proved reserves was primarily the result of additional reserves obtained through an acquisition of interests in our Lions and La Reforma fields and field studies performed in the Midcontinent region.
Results of Operations
The following discussion is of our consolidated results of operations, financial condition and capital resources. You should read this discussion in conjunction with our consolidated financial statements and the related notes thereto contained elsewhere herein. Comparative results of operations for the periods indicated are discussed below.
Year Ended December 31, 2011 Compared to Year Ended December 31, 2010
Sales Volumes
(a) Average daily production volumes calculated based on 365-day year
For the years ended December 31, 2011 and 2010, our net equivalent production volumes decreased by 11% to 2,920 MBoe (8.0 MBoe/d) from 3,287 MBoe (9.0 MBoe/d) in 2010. Our production volumes in 2011 as compared to 2010 decreased primarily due to natural decline in production and the shutting in of producing properties in Louisiana due to flooding from the Mississippi River. Natural gas represented approximately 65% and 69% of our total production in the years ended December 31, 2011 and 2010, respectively.
Revenues. The following tables shows (1) our revenues from the sale of oil; natural gas and NGLs and (2) the impact of changes in price and sales volumes on our oil and natural gas revenues during the year ended December 31, 2011 and 2010. Our commodity hedges are accounted for using mark-to-market accounting, which requires us to record both derivative settlements and unrealized derivative gains (losses) to our consolidated statement of operations within a single income statement line item. We include both commodity derivative settlements and unrealized commodity derivative gains (losses) within revenues.
Our oil, natural gas and NGLs revenues, including derivatives settlements and unrealized gains (losses), for the year ended December 31, 2011 decreased by approximately $3.4 million, or 2%, when compared to the same period in 2010. The pre-hedged revenue increased by approximately $4.0 million. This increase related to higher prices of oil and NGLs of approximately $21.4 million, which was partially offset by lower natural gas prices of approximately $5.2 million and lower production, which decreased revenue by approximately $12.2 million. The decrease in hedged gains was due primarily to lower gains on realized commodity derivatives of approximately $22.3 million and lower unrealized commodity derivatives losses of approximately $15.0 million.
Production costs. Production volumes in the year ended December 31, 2011 decreased by approximately 11% as compared to the same period in 2010 from 3.3 MMBoe to 2.9 MMBoe. Per unit production cost in 2011 increased by $2.48/Boe, or 18%, and total production costs in 2011 increased by approximately $2.0 million, or 4%, as compared to 2010. The increase was attributable to the natural decline in production. Our per unit and total production costs for the years ended December 31, 2011 and 2010 are as set forth below.
Gathering and transportation costs in 2011 were approximately $1.5 million, compared to approximately $1.3 million in 2010, an increase of approximately $0.2 million, or 15%. This increase was primarily due to the increase in our NGLs production.
Operating and maintenance expenses for the year ended December 31, 2011 were approximately $32.0 million, compared to approximately $30.9 million in the same period of 2010, an increase of approximately $1.0 million, or 3%. This increase in operating and maintenance expenses was related to properties acquired in 2010 and 2011 and higher repair costs that was partially offset by lower direct labor and natural gas lift expenses.
Workover expenses for the year ended December 31, 2011 were approximately $3.2 million, compared to approximately $3.4 million for the same period in 2010, a decrease of approximately $0.2 million, or 6%. This decrease was due primarily to a decrease in the number and cost of our workovers in 2011 as compared to 2010.
Environmental remediation expenses for the year ended December 31, 2011 were approximately $2.0 million and were incurred in 2011 as the result of our participation in a settlement involving environmental remediation in a field in which we have an ownership interest. There were no remediation costs incurred in the 2010 period.
Taxes other than income for the year ended December 31, 2011 were approximately $9.9 million, compared to approximately $10.9 million in the same period of 2010, a decrease of $1.0 million or 9%. This decrease in taxes was due to lower actual ad valorem taxes incurred in 2011.
General and administrative expenses. We capitalize a portion of our general and administrative expenses. Capitalized costs include the cost of technical employees who work directly on our exploration activities, a portion of our associated technical organization expenses such as supervision, telephone and postage, and a portion of our interest on unproved capital projects. Our total general and administrative expenses (gross, capitalized and net) and our per unit general and administrative expenses for the years ended December 31, 2011 and 2010 were as follows:
Our gross general and administrative expenses for the year ended December 31, 2011 were approximately $21.0 million compared to approximately $21.3 million in the same period of 2010, a decrease of approximately $0.3 million, or 1%, primarily as a result of there being no stock based compensation expense in 2011. After capitalization, our general and administrative costs decreased by approximately $1.0 million, or 6%, to approximately $16.5 million. Per unit general and administrative expense increased due to a decrease in production volumes, offset by a decrease in compensation expense and an increase in capitalized costs.
Depletion of oil and natural gas properties.
Our depletion expense for the year ended December 31, 2011 was approximately $50.5 million compared to approximately $51.8 million in the same period of 2010, a decrease of approximately $1.3 million, or 3%. This decrease in depletion expense was largely the result of decreased production volumes, which resulted in lower depletion expense by approximately $5.8 million. This was partially offset by an increase in our depletion rate resulting in an increase in depletion expense of approximately $4.5 million.
Impairment of oil and natural gas properties. For the year ended December 31, 2011, based on the average oil and natural gas prices in effect on the first day of each month during 2011 ($4.12 per MMBtu for Henry Hub gas and $96.19 per Bbl for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of our oil and natural gas properties exceeded the ceiling limit and we recorded a $18.2 million impairment to our oil and natural gas properties. We did not record any impairment for the year ended December 31, 2010.
Net interest expense. Our interest expense for the year ended December 31, 2011 and December 31, 2010 was approximately $41.1 million and $48.0 million, respectively. Total interest expense for the year ended December 31, 2011 benefited from our Refinancing that converted the Series A preferred from a debt instrument to mezzanine equity, offset by the increase in interest expense due to the assumption of a higher coupon on our $250 million Notes issued in May 2011.
Income taxes. For the years ended December 31, 2011 and 2010, current tax expense (benefit) was zero and deferred tax expense was approximately zero and $57.4 million, respectively. In 2010, we provided a full valuation allowance with respect to our deferred tax assets given our history of operating losses, and the expectation that future profitability will be impacted significantly by volatility in commodity prices for oil and natural gas. Our future profitability is heavily correlated to the volume of our proved reserves, and the price at which these reserves will be sold. The expected volatility in commodity prices creates significant uncertainty with respect to whether future profitability will be sufficient to realize deferred tax assets.
The federal statutory rate of 35% is different from our effective tax rate primarily as a result of the full valuation allowance against deferred income tax assets.
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
Oil and Natural Gas Reserves
Our estimated total net proved reserves of oil and natural gas as of December 31, 2010 and 2009 were as follows:
Our estimated total net proved reserves increased 19% in the period ended December 31, 2010 as compared to the same period in 2009. This increase in our estimated net proved reserves was primarily the result of additional reserves obtained through an acquisition completed in December 2010.
Sales volumes
(a) Average daily production volumes calculated based on 365-day year
Our net equivalent production volumes for 2010 decreased by 22% to 3,287 MBoe (9.0 MBoe/d) from 4,198 MBoe (11.5 MBoe/d) in 2009. Our production volumes for 2010 decreased primarily due to reduced production-enhancing capital expenditure activity in 2009 and in the first half of 2010 and the natural production decline of our properties. Natural gas represented 69% of our total production in 2010.
Revenues
The following tables shows (1) our revenues from the sale of oil; natural gas and NGLs and (2) the impact of changes in price and sales volumes on our oil and natural gas revenues during the years ended December 31, 2010 and 2009. Our commodity hedges are accounted for using mark-to-market accounting, which requires us to record both derivative settlements and unrealized derivative gains (losses) to our consolidated statement of operations within a single income statement line item. We include both commodity derivative settlements and unrealized commodity derivative gains (losses) within revenues.
Our oil, natural gas and NGLs revenues, including derivatives settlements and unrealized gains for 2010 increased approximately $2.7 million, or 2%, as compared to 2009. This increase in revenues was primarily due to a 33% increase in pre-hedge per Boe sales prices, which resulted in a $28.6 million increase in revenues, and a $2.1 million increase in unrealized gains on derivative hedge contracts from December 31, 2009 to December 31, 2010. This increase in revenues was offset by a 22% decrease in oil and natural gas volumes due to a natural decline in production, resulting in a $23.2 million decrease in revenues, and a $4.8 million decrease in derivative hedging gains on contracts settled.
Production costs. Although production volumes in 2010 decreased approximately 22% as compared to 2009 from 4.2 MMBoe to 3.3 MMBoe in 2010, per unit production cost in 2010 increased by $3.78/Boe, or 36%, and total production costs in 2010 increased by approximately $3.0 million, or 7%, as compared to 2009. Our per unit and total production costs for the years ended December 31, 2010 and 2009 are as set forth below.
Our gathering and transportation costs in 2010 were approximately $1.3 million, compared to approximately $1.9 million in 2009, a decrease of approximately $0.6 million, or 33%. This decrease was primarily due to a reduction in our natural gas production.
Operating and maintenance expenses in 2010 were approximately $30.9 million, compared to approximately $28.5 million in 2009, an increase of $2.4 million, or 8%. This increase in operating and maintenance expenses was due primarily to an increase in well service costs and treating and processing costs.
Workover expenses in 2010 were approximately $3.4 million, compared to approximately $4.0 million in 2009, a decrease of approximately $0.6 million, or 14%. This decrease was due primarily to a decrease in the number and cost of our workovers in 2010 as compared to 2009.
Taxes other than income in 2010 were approximately $10.9 million, compared to approximately $9.0 million in 2009, an increase of approximately $1.9 million or 21%. This increase in taxes other than income was due to utilized tight sands credits in 2009 that were unavailable to us in 2010 because the inventory of properties which became eligible for the credits declined.
General and administrative expenses. We capitalize a portion of our general and administrative expenses. Capitalized costs include the cost of technical employees who work directly on our prospect generation and exploration activities, a portion of our associated technical organization expenses such as supervision, telephone and postage, and a portion of our interest on unproved capital projects. Our total general and administrative expenses (gross, capitalized and net) and our per unit general and administrative expenses for the years ended December 31, 2010 and 2009 are as follows:
Our gross general and administrative expenses in 2010 were approximately $21.3 million compared to approximately $24.5 million in 2009, a decrease of approximately $3.2 million, or 13%. After capitalization, our general and administrative expenses decreased by approximately $1.4 million, or 7%, to approximately $17.5 million. This decrease in our gross general and administrative expenses and our general and administrative expenses after capitalization was largely attributable to certain fees and expenses we paid in 2009 in connection with a recapitalization.
Depletion of oil and natural gas properties.
Our depletion expense for 2010 was approximately $51.8 million compared to approximately $66.9 million in 2009, a decrease of approximately $15.1 million, or 23%. The decrease in depletion expense was primarily attributable to a decrease in production volumes in 2010 resulting in an approximately $14.5 million decrease in depletion expense and a decrease in our depletion rate of approximately $0.6 million. The lower depletion rate was due to our 2009 ceiling limitation impairments.
Impairment of oil and natural gas properties. For the year ended December 31, 2009, based on the average oil and natural gas prices in effect on the first day of each month during 2009 ($3.87 per MMBtu for Henry Hub gas and $61.18 per Bbl for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of our oil and natural gas properties exceeded the ceiling limit and we recorded a $39.6 million impairment to our oil and natural gas properties. We did not record any impairment for the year ended December 31, 2010.
Net interest expense. In 2010, our net interest expense increased by approximately $7.4 million, or 18%, from approximately $40.6 million in 2009 to $48.0 million in 2010. This increase in interest expense was the result of higher interest rates payable on loans under our existing second lien indebtedness as compared to the rates payable under our prior second lien credit agreement and the additional interest expense attributable to the dividends on our Series A preferred stock.
Income taxes. For the years ended December 31, 2010 and 2009, current tax expense (benefit) was zero and deferred tax expense (benefit) was approximately $57.4 million and ($57.4) million, respectively. In 2010, we provided a full valuation allowance with respect to our deferred tax assets given our history of operating losses, and the expectation that future profitability will be impacted significantly by volatility in commodity prices for oil and natural gas. Our future profitability is heavily correlated to the volume of our proved reserves, and the price at which these reserves will be sold. The expected volatility in commodity prices creates significant uncertainty with respect to whether future profitability will be sufficient to realize deferred tax assets.
Effective August 1, 2009, we converted from a single member limited liability company to a corporation taxed under sub-chapter C of the Internal Revenue Code. As a result of the conversion, deferred tax assets and liabilities were recorded to reflect the future tax impacts associated with differences in tax basis as compared to net book value as of the date of conversion. Approximately $77.6 million of net deferred tax assets existed as of the conversion date, before consideration of any valuation allowance.
The federal statutory rate of 35% is different from our effective tax rate primarily because the dividends on our Series A preferred stock (recorded as interest expense) are not deductible for income tax purposes and as a result of the full valuation allowance against deferred income tax assets.
Liquidity and Capital Resources
Historically, we have financed our acquisition, exploitation and development activities, and repayment of our contractual obligations, through a variety of means, including cash flow from operations, borrowings under our credit agreements, issuances of equity and debt securities, reimbursements of prior leasing and seismic costs by third parties who participate in our projects, and the sale of interests in projects and properties. Our primary needs for cash are to fund our capital expenditure program and our working capital obligations and for the repayment of contractual obligations. In the future, we will also require cash to fund our capital expenditures for the exploitation and development of properties necessary to offset the inherent declines in production and proved reserves that are typical in an extractive industry like ours. We will also spend capital to hold acreage that would otherwise expire if not drilled. Future success in growing reserves and production will be highly dependent on our access to cost effective capital resources and our success in economically finding and producing additional oil and natural gas reserves.
Sources and Uses of Cash
The table below summarizes our sources and uses of cash during the periods indicated.
Working capital
At December 31, 2011, we had a working capital deficit of approximately $3.3 million. Our working capital deficit at December 31, 2010 and 2009 was approximately $238.5 million and approximately $11.0 million, respectively. The 2010 deficiency was primarily the result of reclassifying from long-term debt to current debt the approximately $244.6 million outstanding under our prior first lien credit agreement and our prior second lien term loan agreement. The 2009 deficiency was the result of accrued interest of approximately $20.1 million and derivative liabilities of approximately $10.3 million in 2009.
Analysis of cash flows provided by operating activities
Cash flows provided by operating activities in 2011 were approximately $58.4 million, as compared to approximately $95.3 million in 2010, a decrease of approximately $36.9 million, or 39%. The decrease in 2011 was the result of higher operating cost, oil and natural gas receivables and lower accounts payable.
Cash flows provided by operating activities in 2009 were approximately $93.2 million, as compared to approximately $95.3 in 2010, an increase of 2%. The increase in cash flows provided by operating activities from 2009 to 2010 was primarily due to higher oil and natural gas revenues in 2010.
Analysis of cash flows used in investing activities
Net cash used in investing activities in 2011 was approximately $101.4 million, compared to approximately $101.1 million in 2010, a $0.3 million increase.
Our net cash used in investing activities in 2009 was approximately $29.1 million as compared to approximately $101.1 million in 2010, an increase of approximately $72.0 million, or 247%. This increase was primarily due to our acquisition in 2010 of properties from TexCal Energy South Texas, L.P. for $22.4 million and from RWG Energy, Inc. for $44.5 million.
Analysis of cash flows provided by and used in financing activities
Net cash provided by financing activities in 2011 was approximately $34.6 million as compared to approximately $13.0 million provided by financing activities in 2010, an increase of approximately $21.6 million, or 167%. This increase was primarily the result of borrowings in connection with our 2011 Refinancing.
Our net cash used in financing activities in 2009 was approximately $53.6 million as compared to cash provided by financing activities of approximately $13.0 million in 2010, a change of 124%. This increase was the result of $35.0 million of borrowings under our prior second lien term loan agreement to fund our 2010 acquisitions and $25.0 million of borrowings under our prior second lien term loan agreement in connection with our 2010 recapitalization. In 2009, we repaid approximately $53.4 million of outstanding borrowings under our prior first lien credit agreement.
Capital expenditures
The timing of most of our capital expenditures is discretionary because we operate the majority of our wells and we have no material long-term capital expenditure commitments. Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. Our capital expenditure program also includes general and administrative expenses allowed to be capitalized under full cost accounting, costs related to plugging and abandoning unproductive or uneconomic wells and the cost of acquiring and maintaining our lease acreage position and our seismic resources, drilling and completing new oil and natural gas wells, installing new production infrastructure and maintaining, repairing and enhancing existing oil and natural gas wells.
The capital that funds our drilling activities is allocated to individual prospects based on the value potential of a prospect, as measured by a risked net present value analysis. We re-evaluate our annual budget periodically throughout the year. The primary factors that affect our budget include forecasted commodity prices, drilling and completion costs, and a prospect’s risked reserve size and risked initial producing rate. Other factors that are also monitored throughout the year that influence the amount and timing of all our planned expenditures include the level of production from our existing oil and natural gas properties, the availability of drilling and completion services, and the success and resulting production of our newly drilled wells. The outcome of our periodic analysis results in a reprioritization of our drilling schedule to ensure that we are optimizing our capital expenditure plan.
For the year ended December 31, 2011, we spent approximately $92.6 million in capital expenditures to support our business plan. Of this amount we spent approximately $39.5 million to drill or complete eleven gross (8.5 net) wells, of which nine were successful, adding approximately 77 net Boe/d to our 2011 average daily production. We also recompleted or worked over approximately 74 gross (58.6 net) wells during 2011 at a capital cost of approximately $10.2 million, approximately $2.1 million was spent to plug and abandon wells, and spent approximately $11.9 million to acquire seismic data and additional leases primarily in Oklahoma to support the future development of our Atoka Shale properties. The remaining capital expenditures of approximately $28.9 million related primarily to acquisitions.
Capital resources
Cash. As of December 31, 2011 and 2010, we had $9.4 million and $17.7 million of cash and cash equivalents, respectively.
First Lien Credit. As part of the 2011 Refinancing, we entered into the $300 million 2011 Credit Facility that matures in November 2014. The borrowing base for the 2011 Credit Facility is currently $180.0 million with semi-annual redeterminations. The next redetermination date is May 2012. Amounts outstanding under the 2011 Credit Facility bear interest at specified margins over the LIBOR of between 2.75% and 3.75% for Eurodollar loans or at specified margins over the ABR of between 1.75% and 2.75% for ABR loans. Such margins will fluctuate based on the utilization of the facility. Borrowings under the 2011 Credit Facility are secured by all of our oil and natural gas properties. The lenders’ commitments to extend credit will expire, and amounts drawn under the 2011 Credit Facility will mature, in November 2014.
The 2011 Credit Facility contains customary financial and other covenants, including minimum working capital levels (the ratio of current assets plus the unused availability of the borrowing base under the 2011 Credit Facility to current liabilities) of not less than 1.0 to 1.0 (which was 1.85 as of December 31, 2011), minimum interest coverage ratio, as defined, of not less than 2.25 to 1.0 (which was 3.47 as of December 31, 2011), maximum leverage ratio, as defined, of debt balances as compared to EBITDA of not greater than 4.5 to 1.0 (which was 3.98 as of December 31, 2011) and maximum secured leverage ratio, as defined, of secured debt balances as compared to EBITDA of not greater than 2.0 to 1.0 (which was 1.45 as of December 31, 2011). The interest coverage ratio, as defined, increases from 2.25 to 1.0 during 2011 and 2.5 to 1.0 thereafter. The leverage ratio, as defined, is 4.5 to 1.0 for 2011. The leverage ratio for the first quarter of 2012 was waived and then will reduce to 4.25 to 1.0 for the remainder of 2012 and 4.0 to 1.0 thereafter. In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt and liens, changes of control and asset sales. At December 31, 2011, we were in compliance with the financial covenants governing the 2011 Credit Facility. Under the 2011 Credit Facility, the maximum amount of debt outstanding in 2011 was $149,500,000 on November 15, 2011 and the average daily balance of debt outstanding during 2011 was $114,502,128.
Series A Preferred Stock. As part of the 2010 recapitalization, we entered into agreements to exchange a portion of prior second lien indebtedness for $205.5 million of Series A preferred stock, consisting of 2,700,000 shares issued at $76.12 per share redeemable in 2016 at the option of the holder subsequent to the maturity of certain qualified debt, including the 2011 Credit Facility and the Notes. The preferred shareholders receive a 12% dividend each year paid in-kind. There were no dividends declared or paid during 2010 or 2011. The Series A stock was classified as a liability in the financial statements prior to May 11, 2011, as they were mandatorily redeemable for cash.
Upon completion of the 2011 Refinancing, including the amendment of the terms of our Series A preferred stock as described in Note 10 to the consolidated financial statements included herein, we reclassified the Series A preferred stock as mezzanine equity for financial reporting purposes because there is no longer a mandatory redemption provision and the Series A preferred stock is redeemable at the option of the holder
Capitalization of Debt Costs. We capitalize certain direct costs associated with the issuance of long-term debt, which is then amortized over the lives of the respective debt using the straight-line method, which approximates the interest method.
Senior Secured Second Lien Notes. As part of the 2011 Refinancing, we issued Senior Secured Second Lien Notes due May 11, 2016 with a face value of $250 million, at a discount of $7.0 million. The Notes carry a face interest rate of 10.500%; interest is payable semi-annually each May 15 and November 15. The Notes are secured by a second priority lien on all of the collateral securing the 2011 Credit Facility, and effectively rank junior to any existing and future first lien secured indebtedness, which includes the 2011 Credit Facility. The balance is presented net of unamortized discount of $6.1 million at December 31, 2011.
The Notes contain an optional redemption provision allowing us to retire up to 35% of the principal outstanding with the proceeds of an equity offering, at 110.5% of par. Additional optional redemption provisions allow for the retirement of all or a portion of the outstanding senior secured second lien notes at 110.5%, 102.625% and 100.0% beginning on each of May 15, 2014, May 15, 2015 and November 15, 2015, respectively. If a change of control occurs, each noteholder may require us to repurchase all or a portion of its notes for cash at a price equal to 101% of the aggregate principal amount of such notes, plus any accrued and unpaid interest and special interest, if any, to, but not including, the date of repurchase. The indenture governing the Notes contains covenants that, among other things, limit our ability to incur or guarantee additional indebtedness or issue certain preferred stock; declare or pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; transfer or sell assets; make investments; create certain liens; consolidate, merge or transfer all or substantially all of its assets; engage in transactions with affiliates; and create unrestricted subsidiaries.
Outlook
We expect to fund our acquisition, exploitation and development activities from a variety of sources, including through cash flow from operations, borrowings under our 2011 Credit Facility, issuances of equity and debt securities, reimbursements of prior leasing and seismic costs by third parties who participate in our projects, and the sale of interests in projects and properties. However, we expect that future significant acquisitions will require funding, at least in part, from the proceeds of the issuance of equity securities.
As of December 31, 2011, we had approximately $40.4 million of available borrowing capacity under our 2011 Credit Facility.
For the year ended December 31, 2011, we realized approximately $17.0 million in gains under our hedging agreements. Based on the NYMEX strip pricing for oil and natural gas as of December 31, 2011, we expect to realize approximately $7.5 million of hedging revenues during 2012.
For 2012, our capital program is approximately $54.2 million, which we believe is sufficient to maintain current operations. Our 2012 capital budget contemplates spending approximately $14.2 million in connection with the drilling of eight additional wells and approximately $11.3 million in connection with the workover and recompletion of existing wells. We have also budgeted approximately $25.0 million for acquisitions.
The table below sets forth our 2012 capital budget.
The final determination with respect to our actual capital expenditures during 2012 will depend on a number of factors, including:
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changes in commodity prices;
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changes in service and materials costs, including from the sharing of costs through the formation of joint ventures with other oil and natural gas companies;
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production from our existing producing wells;
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the results of our current exploitation and development drilling efforts;
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economic and industry conditions at the time of drilling;
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our liquidity and the availability of financing; and
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properties for sale at an attractive price and rate of return.
Off Balance Sheet Arrangements
We currently do not have off balance sheet arrangements or other such unrecorded obligations, and we have not guaranteed the indebtedness of any other party.
Contractual Obligations
In the schedule below, we set forth our contractual obligations as of December 31, 2011 and the effect those obligations are expected to have on our future cash flow and liquidity.
(1) Includes $6.1 million of original issue discount that will become due upon maturity.
(2) Consists of fees payable to an investment bank for advisory services related to acquisitions.
(3) Consists primarily of leases for office space and office equipment.
Critical Accounting Policies
The establishment and consistent application of accounting policies is a vital component of accurately and fairly presenting our consolidated financial statements in accordance with GAAP, as well as ensuring compliance with applicable laws and regulations governing financial reporting. While there are rarely alternative methods or rules from which to select in establishing accounting and financial reporting policies, proper application often involves significant judgment regarding a given set of facts and circumstances and a complex series of decisions.
Use of Estimates
The preparation of our consolidated financial statements in conformity with U.S. GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. These estimates include oil and natural gas reserve quantities that form the basis for (i) the allocation of purchase price to proved and unproved properties; (ii) calculation of amortization of oil and natural gas properties and (iii) the full cost ceiling test. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories. Other significant estimates include (a) estimated quantities and prices of oil and natural gas sold, but not collected, as of period-end; (b) accruals of capital and operating costs; (c) current plug and abandonment costs, settlement date, inflation rate and credit-adjusted risk-free rate used in estimating asset retirement obligations; and (d) those assumptions and calculation techniques used in estimating the fair value of derivative financial instruments, as considered in Note 7. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements.
Oil and Natural Gas Properties
Full Cost Accounting - We utilize the full cost method to account for our investment in oil and natural gas properties. Under the full cost method, which is governed by Rule 4-10 of Regulation S-X of the SEC, all costs of acquisition, exploration, exploitation, and development of oil and natural gas reserves (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible exploration and development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred. Accordingly, we capitalize the cost to acquire, explore for and develop oil and natural gas properties. Direct internal costs that are capitalized are primarily the salary and benefits of geologists, landmen, and engineers directly involved in acquisition, exploration and development activities. There were approximately $4.5 million, $3.8 million and $5.6 million of direct internal costs capitalized for the years ended December 31, 2011, 2010 and 2009, respectively.
Depreciation, Depletion, and Amortization - The cost of oil and natural gas properties, the estimated future expenditures to develop proved reserves and estimated future abandonment, site remediation and dismantlement costs are depleted and charged to operations using the unit-of-production method based on the ratio of current production to proved oil and natural gas reserves as estimated by independent engineering consultants. Our depletion rates for the years ended December 31, 2011, 2010 and 2009 were $17.28, $15.75 and $15.93 per Mboe, respectively.
Impairment - Full cost ceiling impairment is calculated whereby net capitalized costs related to proved and unproved properties less related deferred income taxes may not exceed a ceiling limitation. The ceiling limitation is the amount equal to the present value discounted at 10% of estimated future net revenues from estimated proved reserves plus the lower of cost or fair value of unproved properties less estimated future production and development costs and net of related income tax effect. The full cost ceiling limitation is calculated using 12-month simple average price of oil and natural gas as of the first day of each month for the period ending as of the balance sheet date and is adjusted for “basis” or location differentials. Price and operating costs, which are based on current cost conditions, are held constant over the life of the reserves. If net capitalized costs related to proved properties less related deferred income taxes exceed the ceiling limitation, the excess is impaired and a permanent write-down is recorded in the consolidated statements of operations. An impairment of approximately $18.2 million was recorded for the year ended December 31, 2011, no impairment was recorded for the year ended December 31, 2010 and an impairment of approximately $39.6 million was recorded for the year ended December 31, 2009.
Unproved Property Costs - Costs directly associated with the acquisition and evaluation of unproved properties, including leasehold, acreage, and capitalized interest, are excluded from the full cost pool until it is determined whether or not proved reserves can be assigned to the individual prospects or whether impairment has occurred.
We assess all items classified as unproved property on a quarterly basis for possible impairment or reduction in value. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.
Unproved property costs fall into two broad categories:
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Leasehold costs for projects not yet evaluated and
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Interest
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Costs related to financing such activities.
Revenue Recognition and Natural Gas Imbalances
Revenues are recognized and accrued as production occurs and physical possession and title pass to the customer.
We use the sales method of accounting for revenue. Under this method, oil and natural gas revenues are recorded for the amount of oil and natural gas production sold to purchasers. Natural gas imbalances are created when the sales amount is not equal to our entitled share of production. Our entitled share is calculated as gross production from the property multiplied by our net revenue interest in the property. No provision is made for an imbalance unless the oil and natural gas reserves attributable to a property have depleted to the point that there are insufficient reserves to satisfy existing imbalance positions. At that point, a payable or a receivable, as appropriate, is recorded equal to the net value of the imbalance. As of December 31, 2011 and 2010, we had recorded a liability of approximately $597,000 and $725,000, respectively.
Income Taxes
Income taxes are accounted for using the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets also arise when operating losses or tax credits are available to offset future taxable income. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in operations in the period that includes the date when the change in the tax rate was enacted.
We routinely assess the realizability of our deferred tax assets. If it is more likely than not that some portion or all of the deferred tax assets will not be realized, the deferred tax asset is reduced by a valuation allowance.
As a result of the conversion to a corporation on August 1, 2009, which pursuant to Sec. 351 of the Internal Revenue Code, a tax-free reorganization, we stepped into the “shoes” of our parent company as to the tax value of the net assets. Therefore, in effect, the income tax years of 2008, through the conversion date, through the current year, remain open and subject to examination by Federal tax authorities and/or the tax authorities in Texas, Oklahoma, Mississippi, and Louisiana which are our principal operating jurisdictions. These audits can result in adjustments of taxes due or adjustments of the net operating loss carry forwards that are available to offset future taxable income.
A more-likely-than-not recognition threshold (assuming taxing authorities have full knowledge of the facts and based solely on the technical merits) and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return.
Our policy is to recognize interest and penalties related to uncertain tax positions as income tax benefit (expense) in our Consolidated Statements of Operations. No interest expense or penalties related to unrecognized tax benefits associated with uncertain tax positions have been recognized in the provision for income taxes in any year presented.
The total amount of unrecognized tax benefit if recognized that would affect the effective tax rate was zero.
Our parent files a consolidated tax return in Texas for the Texas Margin Tax, and is the legally responsible party for such taxes. Therefore, any income tax associated with the Texas Margin Tax is the responsibility of our parent, and has not been recognized in our consolidated financial statements. There are no income tax sharing agreements between our parent and us.
See Note 12 - “Income Taxes” for further information.
Derivative Financial Instruments
We utilize derivative financial instruments, specifically, commodity swaps and collars and interest rate collars. Commodity swaps and collars are used to manage market price exposures associated with sales of oil and natural gas. Interest rate collars are used to manage interest rate risk arising from interest payments associated with floating rate debt. Such instruments are entered into for non-trading purposes.
Derivative contracts have not been designated nor do they qualify for hedge accounting. The valuation of these instruments is determined using valuation techniques, including discounted cash flow analysis on the expected cash flows of each derivative. This analysis reflects the contractual terms of the derivatives, including the period to maturity, and uses observable market-based inputs, including price volatility and commodity and interest rate forward curves as appropriate.
We incorporate credit valuation adjustments to appropriately reflect both our nonperformance risk and the respective counterparty’s nonperformance risk in the fair value measurements. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, any impacts of netting and any applicable credit enhancements, such as collateral postings, thresholds, and guarantees, are considered.
Asset Retirement Obligation
We record a liability for the estimated fair value of our asset retirement obligations, primarily comprised of our plugging and abandonment liabilities, in the period in which it is incurred. The liability is accreted each period through charges to accretion expense. The asset retirement cost is included in the full cost pool. If the liability is settled for an amount other than the recorded amount, the difference is recognized in oil and natural gas properties.
Recently Issued Accounting Pronouncements
In December 31, 2008, the SEC issued “Modernization of Oil and Gas Reporting” (ASC 2010-3), which amends the oil and gas disclosures for oil and gas producers contained in Regulations S-K and S-X, as well as adding a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being eliminated. The goal of the final release is to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. Energy companies affected by the release are now required to price proved oil and gas reserves using the unweighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. The final release is effective for financial statements with fiscal years ending on or after December 31, 2009. We adopted the provisions of the rule effective December 31, 2009.
In January 2010, the FASB issued Accounting Standards Update (ASU) 2010-06, “Improving Disclosures About Fair Value Measurements” (“ASU 2010-06”), which amends the Fair Value Measurements and Disclosures Topic of the ASC (“ASC Topic 820”). Among other provisions, ASC Topic 820 establishes a fair value hierarchy that prioritizes the relative reliability of inputs used in fair value measurements. The hierarchy gives highest priority to Level 1 inputs that represent unadjusted quoted market prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are directly or indirectly observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs and have the lowest priority in the hierarchy. This amendment requires new disclosures on the value of, and the reason for, transfers in and out of Levels 1 and 2 of the fair value hierarchy and additional disclosures about purchases, sales, issuances and settlements within Level 3 fair value measurements. ASU 2010-06 also clarifies existing disclosure requirements on levels of disaggregation and about inputs and valuation techniques. ASU 2010-06 became effective for interim and annual reporting periods beginning after December 15, 2009, except for the requirement to provide additional disclosures regarding Level 3 measurements which became effective for interim and annual reporting periods beginning after December 15, 2010. See Note 7 to the consolidated financial statements included herein. We adopted the applicable provisions of the rule effective January 1, 2010 and January 1, 2011, respectively.
In May 2011, the FASB issued ASU No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. This ASU expands existing disclosure requirements for fair value measurements and provides additional information on how to measure fair value. The Company is required to apply this ASU prospectively for interim and annual periods beginning after December 15, 2011. The Company is currently evaluating the potential impact of this adoption on its consolidated financial statements.
On December 16, 2011, the FASB issued ASU No. 2011-11, Disclosures about Offsetting Assets and Liabilities, in conjunction with the IASB’s issuance of amendments to Disclosures-Offsetting Financial Assets and Financial Liabilities (Amendments to IFRS 7). While the FASB and IASB retained the existing offsetting models under U.S. GAAP and IFRS, the new standards require disclosures to allow investors to better compare financial statements prepared under U.S. GAAP with financial statements prepared under IFRS. The new standards are effective for annual periods beginning Jan. 1, 2013, and interim periods within those annual periods. Retrospective application is required. We are currently evaluating the potential impact of this adoption on its consolidated financial statements.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosure About Market Risk
Interest Rate Risk
We are exposed to changes in interest rates that affect the interest paid on borrowings under the 2011 Credit Facility. The Company currently is not party to any interest rate hedging arrangements that would mitigate the risk of increasing interest rates. The interest paid on the Notes is fixed at 10.500% per annum and is not subject to changes in floating interest rates. Based on our current capital structure at December 31, 2011, a 1% increase in interest rates would increase interest expense by approximately $1.4 million per year, based on our approximately $138.0 million of floating rate indebtedness outstanding under our existing 2011 Credit Facility that would be affected by such a movement in interest rates.
Concentration of Credit Risk
Financial instruments that potentially subject us to concentrations of credit risk consist principally of temporary cash investments, trade accounts receivable and derivative instruments. We believe that we place our excess cash investments with strong financial institutions. Our receivables generally relate to customers in the oil and natural gas industry, and as such, we are directly affected by the economy of the industry. During 2011, ten customers collectively accounted for 70% of our oil and natural gas revenues and during 2010, ten customers collectively accounted for 69% of our oil and natural gas revenues. This concentration increases our credit risk. We seek to mitigate our credit risk by, among other things, monitoring customer creditworthiness.
Counterparty Risk
We have exposure to financial institutions in the form of derivative transactions in connection with our hedges. These transactions are with counterparties in the financial services industry, specifically with members of our bank group. These transactions could expose us to credit risk in the event of default of our counterparties. In addition, we also have exposure to financial institutions which are lenders under our credit facilities. If any lender under our existing first lien credit agreement, or under our 2011 Credit Facility, is unable to fund its commitment, our liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitment under the 2011 Credit Facility.
Commodity Price Risk
Changes in commodity prices significantly affect our capital resources, liquidity and operating results. Price changes directly affect revenues and can indirectly impact expected production by changing the amount of capital we have available to reinvest in our exploitation and development activities. Commodity prices are impacted by many factors that are outside of our control. Over the past few years, commodity prices have been highly volatile. We expect that commodity prices will continue to fluctuate significantly in the future. As a result, we cannot accurately predict future oil and natural gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues.
The prices we receive for our oil production are based on global market conditions. Significant factors that impacted oil prices in 2011 included the pace at which the domestic and global economies recovered from the current recession, the ongoing tensions and uprisings in the Middle East and North Africa, and the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations were able to manage oil supply through export quotas.
Natural gas prices are primarily driven by North American market forces. However, global LNG shipments can impact North American markets to the extent cargoes are diverted from Asia or Europe to North America. Factors that can affect the price of natural gas include changes in market demand, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials, and other factors. Over the past several years, natural gas prices have been volatile. Our average pre-hedged sales price for natural gas in 2011 was $3.93 per Mcf, which was approximately 10% lower than the price of $4.39 per Mcf that we received during 2010. Natural gas prices in 2011 were dependent upon many factors including the balance between North American supply and demand.
We have utilized swaps and costless collars to (i) reduce the effect of price volatility on the commodities that we produce and sell, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure that we can execute at least a portion of our capital spending plans with internally generated funds. The following table details derivative contracts that settled during 2011 and includes the type of derivative contract, the volume, the weighted average NYMEX reference price for those volumes, and the associated gain/(loss) upon settlement.
The following derivatives contracts were in place as of December 31, 2011
Item 8.
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Milagro Oil & Gas, Inc.
Houston, Texas
We have audited the accompanying consolidated balance sheets of Milagro Oil & Gas, Inc. and subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, changes in stockholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the 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. The Company is not required to have, nor were we engaged to perform, an audit of its 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, such consolidated financial statements present fairly, in all material respects, the financial position of Milagro Oil & Gas, Inc. and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 3 to the consolidated financial statements, the Company changed its method of accounting for oil and natural gas reserves and disclosures on December 31, 2009.
/s/ Deloitte & Touche LLP
Houston, Texas
March 29, 2012
MILAGRO OIL & GAS, INC.
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2011 AND 2010
See notes to consolidated financial statements.
MILAGRO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2011, 2010, AND 2009
See notes to consolidated financial statements.
MILAGRO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT)
FOR THE YEARS ENDED DECEMBER 31, 2011, 2010, AND 2009
* Upon written consent of the Board of Directors and Members of the Company, effective on August 1, 2009, the Company converted from an LLC to a corporation under Sub Chapter C of the Internal Revenue Code.
See notes to consolidated financial statements.
MILAGRO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2011, 2010, AND 2009
See notes to consolidated financial statements.
MILAGRO OIL & GAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2011, 2010, AND 2009
1. ORGANIZATION
Milagro Oil & Gas, Inc. (the “Company” or “Milagro”) is an independent oil and natural gas exploration and production company. The Company was organized as a Delaware limited liability company on November 30, 2007. The Company owns 100% of Milagro Exploration, LLC, Milagro Resources, LLC, Milagro Producing, LLC and Milagro Mid-Continent, LLC and is a subsidiary of Milagro Holdings, LLC (“Parent”). Each of these subsidiaries is included in the consolidated financial statements. All intercompany accounts and transactions are eliminated in consolidation.
Milagro’s historic geographic focus has been along the onshore Gulf Coast area, primarily in Texas, Louisiana and Mississippi. The Company operates a significant portfolio of oil and natural gas producing properties and mineral interests in this region and has expanded its footprint through the acquisition and development of additional producing or prospective properties in North Texas and Western Oklahoma.
2. ACQUISITIONS
Management considers the most significant fair value estimates associated with acquisitions to be proved oil and natural gas properties. The fair value of proved properties was estimated utilizing the value of underlying oil and natural gas reserves as of the transaction date. The acquisitions are accounted for using the acquisition method of accounting. The estimation of the fair value of derivatives is described in Note 7.
NEWFIELD - On September 29, 2011, the Company completed the acquisition of certain Texas Gulf Coast and South Texas assets from Newfield Exploration Company, for a purchase price of $28.0 million, subject to normal and customary purchase price adjustments. The assets acquired in the transaction include producing wells in Goliad and Hidalgo Counties, Texas. The estimated fair values of the assets acquired and liabilities assumed were oil and natural gas properties of $26.8 million, asset retirement obligations of $1.9 million and other liabilities of $164,000. The acquisition was funded with cash on hand and proceeds from borrowings.
RAM - On December 8, 2010, the Company completed the acquisition of certain North Texas assets from RWG Energy, Inc., a wholly-owned subsidiary of RAM Energy Resources, Inc., for a purchase price of $43.75 million, subject to normal and customary purchase price adjustments. The assets acquired in the transaction include producing wells in Jack and Wise Counties, Texas. The estimated fair values of the assets acquired and liabilities assumed were oil and natural gas properties of $44.5 million, other assets of $91,000, asset retirement obligations of $766,000 and other liabilities of $2.4 million. The acquisition was funded with cash on hand and proceeds from borrowings. In 2011, the Company completed the remediation activities contemplated at the time of acquisition, which resulted in a $1.5 million reduction of other liabilities and oil and natural gas properties.
Venoco - On May 14, 2010, the Company completed the acquisition of certain Gulf Coast assets of TexCal Energy South Texas, L.P., a subsidiary of Venoco, Inc., for a purchase price of $24.0 million, subject to normal and customary purchase price adjustments. The assets acquired in the transaction included producing wells in various counties along the Texas Gulf Coast. The estimated fair values of the assets acquired and liabilities assumed were oil and natural gas properties of $22.4 million, other assets of $34,000, asset retirement obligations of $1.8 million and other liabilities of $0.5 million. The acquisition was funded with proceeds from borrowings.
The following table reflects pro forma oil and natural gas revenues and net loss for the year ended December 31, 2010 as if these acquisitions had taken place on January 1, 2009. There were no acquisitions in 2009. These unaudited pro forma amounts do not purport to be indicative of the results that would have actually been obtained during the periods presented or that may be obtained in the future.
Actual oil and natural gas revenues and net income before taxes recorded in 2010 from the acquisitions were approximately $6.3 million and $3.6 million, respectively.
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates - The preparation of the Company’s consolidated financial statements in conformity with U.S. GAAP requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. These estimates include oil and natural gas reserve quantities that form the basis for (i) the allocation of purchase price to proved and unproved properties, (ii) calculation of amortization of oil and natural gas properties and (iii) the full cost ceiling test. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories. Other significant estimates include (a) estimated quantities and prices of oil and natural gas sold, but not collected, as of period-end; (b) accruals of capital and operating costs; (c) current plug and abandonment costs, settlement date, inflation rate and credit-adjusted risk-free rate used in estimating asset retirement obligations; and (d) those assumptions and calculation techniques used in estimating the fair value of derivative financial instruments, as considered in Note 7. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s consolidated financial statements.
Oil and Natural Gas Properties:
Full Cost Accounting - The Company utilizes the full cost method to account for its investment in oil and natural gas properties. Under the full cost method, which is governed by Rule 4-10 of Regulation S-X of the SEC, all costs of acquisition, exploration, exploitation, and development of oil and natural gas reserves (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible exploration and development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred. Accordingly, we capitalize the cost to acquire, explore for and develop oil and natural gas properties. Direct internal costs that are capitalized are primarily the salary and benefits of geologists, landmen, and engineers directly involved in acquisition, exploration and development activities. There were approximately $4.5 million, $3.8 million and $5.6 million of direct internal costs capitalized for the years ended December 31, 2011, 2010 and 2009, respectively.
Depreciation, Depletion, and Amortization - The cost of oil and natural gas properties; the estimated future expenditures to develop proved reserves; and estimated future abandonment, site remediation and dismantlement costs are depleted and charged to operations using the unit-of-production method based on the ratio of current production to proved oil and natural gas reserves as estimated by independent engineering consultants. The Company’s depletion rates for the years ended December 31, 2011, 2010 and 2009 were $17.28, $15.75 and $15.93 per Mboe, respectively.
Impairment - Full cost ceiling impairment is calculated whereby net capitalized costs related to proved and unproved properties less related deferred income taxes may not exceed a ceiling limitation. The ceiling limitation is the amount equal to the present value discounted at 10% of estimated future net revenues from estimated proved reserves plus the lower of cost or fair value of unproved properties less estimated future production and development costs and net of related income tax effect. The full cost ceiling limitation is calculated using 12-month simple average price of oil and natural gas as of the first day of each month for the period ending as of the balance sheet date and is adjusted for “basis” or location differentials. Price and operating costs, which are based on current cost conditions, are held constant over the life of the reserves. If net capitalized costs related to proved properties less related deferred income taxes exceed the ceiling limitation, the excess is impaired and a permanent write-down is recorded in the consolidated statements of operations. An impairment of approximately $18.2 million was recorded for the year ended December 31, 2011, no impairment was recorded for the year ended December 31, 2010 and an impairment of approximately $39.6 million was recorded for the year ended December 31, 2009.
Unproved Property Costs - Costs directly associated with the acquisition and evaluation of unproved properties, including leasehold, acreage, and capitalized interest, are excluded from the full cost pool until it is determined whether or not proved reserves can be assigned to the individual prospects or whether impairment has occurred.
The Company assesses all items classified as unproved property on a quarterly basis for possible impairment or reduction in value. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.
Unproved property costs fall into two broad categories:
•
Leasehold costs for projects not yet evaluated and
•
Interest costs related to financing such activities.
Sales of Properties - Dispositions of oil and natural gas properties held in the full cost pool are recorded as adjustments to net capitalized costs, with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas.
Other Property, Plant and Equipment - Other operating property and equipment are stated at cost. The provision for depreciation is calculated using the straight-line method over the estimated useful lives of the respective assets. The cost of normal maintenance and repairs is charged to operating expense as incurred. Material expenditures that increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of properties sold or otherwise disposed of and the related accumulated depreciation or amortization is removed from the accounts, and any gains or losses are reflected in current operations.
Revenue Recognition and Natural Gas Imbalances - Revenues are recognized and accrued as production occurs and physical possession and title pass to the customer. The Company uses the sales method of accounting for revenue. Under this method, oil and natural gas revenues are recorded for the amount of oil and natural gas production sold to purchasers. Natural gas imbalances are created when the sales amount is not equal to the Company’s entitled share of production. The Company’s entitled share is calculated as gross production from the property multiplied by the Company’s net revenue interest in the property. No provision is made for an imbalance unless the oil and natural gas reserves attributable to a property have depleted to the point that there are insufficient reserves to satisfy existing imbalance positions. At that point, a payable or a receivable, as appropriate, is recorded equal to the net value of the imbalance. As of December 31, 2011 and 2010, the Company had recorded a liability of approximately $597,000 and $725,000, respectively.
Accounts Receivable -Substantially all of the Company’s accounts receivable are due from purchasers of oil and natural gas or from reimbursable expenses billed to the other participants in oil and natural gas wells for which the Company serves as operator. Oil and natural gas sales are generally unsecured.
As is common industry practice, collateral or other security is generally not required as a condition of sale; rather, the Company relies on credit approval, balance limitation, and monitoring procedures to control the credit approval on accounts receivable. The Company also grants credit to joint owners of oil and natural gas properties, which the Company operates through its subsidiaries. The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. The Company periodically reviews the accounts receivable from all customers for collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to allowance. As of December 31, 2011 and December 31, 2010, the Company had allowances of approximately $0.8 million and $0.6 million, respectively. There were no significant write-offs of receivables for the years ended December 31, 2011 or the year ended December 31, 2010 and no significant bad debt expense recorded for the same periods.
Prepaid and Other Current Assets:
Prepaid Expenses - The Company will occasionally prepay certain costs that may include insurance, maintenance agreements or rent. These costs are then amortized or expensed in the period the work or service is performed. As of December 31, 2011 and December 31, 2010, the Company had prepaid expense of approximately $1.9 million and $1.5 million, respectively, primarily related to insurance.
Other - The Company is required to make advances to operators for costs incurred on a day-to-day basis to develop and operate ventures in which the Company has an ownership interest. These advances totaled approximately $0.2 million as of both December 31, 2011 and December 31, 2010. Such costs are capitalized to the full cost pool at the time the operator develops the properties. Other assets included a prepaid escrow of approximately $0.7 million and $0.8 million as of both December 31, 2011 and 2010, respectively.
Income Taxes - Income taxes are accounted for using the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets also arise when operating losses or tax credits are available to offset future taxable income. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in operations in the period that includes the date when the change in the tax rate was enacted.
The Company routinely assesses the realizability of its deferred tax assets. If it is more likely than not that some portion or all of the deferred tax assets will not be realized, the deferred tax asset is reduced by a valuation allowance.
As a result of the conversion to a corporation on August 1, 2009, pursuant to IRS Sec. 351, a tax-free reorganization, the Company stepped into the “shoes” of the parent company as to the tax value of the net assets. Therefore, in effect, the income tax years of 2008, through the conversion date, through the current year remain open and subject to examination by Federal tax authorities and/or the tax authorities in Texas, Oklahoma, Mississippi, and Louisiana which are the Company’s principal operating jurisdictions. These audits can result in adjustments of taxes due or adjustments of the net operating loss carry forwards that are available to offset future taxable income.
A more-likely-than-not recognition threshold (assuming taxing authorities have full knowledge of the facts and based solely on the technical merits) and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return is utilized.
The Company’s policy is to recognize interest and penalties related to uncertain tax positions as income tax benefit (expense) in its Consolidated Statements of Operations. No interest expense or penalties related to unrecognized tax benefits associated with uncertain tax positions have been recognized in the provision for income taxes in any year presented.
The total amount of unrecognized tax benefit if recognized that would affect the effective tax rate was zero.
The Parent files a consolidated tax return in Texas for the Texas Margin Tax, and is the legally responsible party for such taxes. Therefore, any income tax associated with the Texas Margin Tax is the responsibility of Parent, and has not been recognized in the Company’s financial statements. There are no income tax sharing agreements between Parent and the Company
See Note 12 - “Income Taxes” for further information.
Cash and Cash Equivalents - The Company considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. Cash and cash equivalents are maintained with major financial institutions and such deposits may exceed the amount of federally backed insurance provided. While the Company regularly monitors the financial stability of such institutions, cash and cash equivalents ultimately remain at risk subject to the financial viability of such institutions.
Derivative Financial Instruments - The Company utilizes derivative financial instruments, specifically, commodity swaps and collars and interest rate collars. Commodity swaps and collars are used to manage market price exposures associated with sales of oil and natural gas. Interest rate collars are used to manage interest rate risk arising from interest payments associated with floating rate debt. Such instruments are entered into for non-trading purposes.
Derivative contracts have not been designated nor do they qualify for hedge accounting. The valuation of these instruments is determined using valuation techniques, including discounted cash flow analysis on the expected cash flows of each derivative. This analysis reflects the contractual terms of the derivatives, including the period to maturity, and uses observable market-based inputs, including price volatility and commodity and interest rate forward curves as appropriate.
The Company incorporates credit valuation adjustments to appropriately reflect both its nonperformance risk and the respective counterparty’s nonperformance risk in the fair value measurements. In adjusting the fair value of its derivative contracts for the effect of nonperformance risk, any impacts of netting and any applicable credit enhancements, such as collateral postings, thresholds, and guarantees, are considered.
Deferred Financing Fees - The Company capitalizes certain direct costs associated with the issuance of long-term debt, which is then amortized over the lives of the respective debt using the straight-line method, which approximates the interest method.
Asset Retirement Obligation - The Company records a liability for the estimated fair value of its asset retirement obligations, primarily comprised of its plugging and abandonment liabilities, in the period in which it is incurred. The liability is accreted each period through charges to accretion expense. The asset retirement cost is included in the full cost pool. If the liability is settled for an amount other than the recorded amount, the difference is recognized in oil and natural gas properties.
Reclassifications - The Company reclassified amounts relating to accounts payable and accrued liabilities on the 2010 balance sheet to conform to the current year’s presentation. This reclassification has no effect on total stockholders’ equity, net income or cash flows as previously reported.
Stock-Based Compensation - The Company estimates the fair value of stock-based compensation provided to employees. When and if issued, the Company estimates the fair value of stock-based compensation at the grant date, and recognizes compensation expense over the period that the employees provide the required service. No new grants of stock-based compensation were provided by the Company in any period presented and stock-based compensation recognized during 2010 and 2009 represent amortization of previous grants over the initial vesting period.
Subsequent Events - The Company evaluated subsequent events through the date the financial statements were issued.
Recently Issued Accounting Pronouncements - In December 31, 2008, the SEC issued “Modernization of Oil and Gas Reporting” (ASC 2010-3), which amends the oil and gas disclosures for oil and gas producers contained in Regulations S-K and S-X, as well as adding a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being eliminated. The goal of the final release is to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. Energy companies affected by the release are now required to price proved oil and gas reserves using the unweighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. The final release is effective for financial statements with fiscal years ending on or after December 31, 2009. The Company adopted the provisions of the rule effective December 31, 2009.
In January 2010, the FASB issued Accounting Standards Update (ASU) 2010-06, “Improving Disclosures About Fair Value Measurements” (“ASU 2010-06”), which amends the Fair Value Measurements and Disclosures Topic of the ASC (“ASC Topic 820”). Among other provisions, ASC Topic 820 establishes a fair value hierarchy that prioritizes the relative reliability of inputs used in fair value measurements. The hierarchy gives highest priority to Level 1 inputs that represent unadjusted quoted market prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are directly or indirectly observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs and have the lowest priority in the hierarchy. This amendment requires new disclosures on the value of, and the reason for, transfers in and out of Levels 1 and 2 of the fair value hierarchy and additional disclosures about purchases, sales, issuances and settlements within Level 3 fair value measurements. ASU 2010-06 also clarifies existing disclosure requirements on levels of disaggregation and about inputs and valuation techniques. ASU 2010-06 became effective for interim and annual reporting periods beginning after December 15, 2009, except for the requirement to provide additional disclosures regarding Level 3 measurements which became effective for interim and annual reporting periods beginning after December 15, 2010. See Note 7 to the consolidated financial statements. The Company adopted the applicable provisions of the rule effective January 1, 2010 and January 1, 2011, respectively.
In May 2011, the FASB issued ASU No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. This ASU expands existing disclosure requirements for fair value measurements and provides additional information on how to measure fair value. The Company is required to apply this ASU prospectively for interim and annual periods beginning after December 15, 2011. The Company is currently evaluating the potential impact of this adoption on its consolidated financial statements.
On December 16, 2011, the FASB issued ASU No. 2011-11, Disclosures about Offsetting Assets and Liabilities, in conjunction with the IASB’s issuance of amendments to Disclosures-Offsetting Financial Assets and Financial Liabilities (Amendments to IFRS 7). While the FASB and IASB retained the existing offsetting models under U.S. GAAP and IFRS, the new standards require disclosures to allow investors to better compare financial statements prepared under U.S. GAAP with financial statements prepared under IFRS. The new standards are effective for annual periods beginning Jan. 1, 2013, and interim periods within those annual periods. Retrospective application is required. The Company is currently evaluating the potential impact of this adoption on its consolidated financial statements.
4. CONCENTRATION OF CREDIT RISK
Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of temporary cash investments, trade accounts receivable and derivative financial instruments.
The Company places its excess cash investments with high quality financial institutions. The Company’s receivables relate to customers in the oil and natural gas industry, and as such, the Company is directly affected by the economy of the industry. The credit risk associated with the receivables is mitigated by monitoring customer creditworthiness.
For the years ended December 31, 2011, 2010 and 2009, the Company’s most significant customers by reference to oil and natural gas revenue were as follows:
5. ASSET RETIREMENT OBLIGATION
In general, the amount of an asset retirement obligation (“ARO”) and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using a credit-adjusted risk-free rate.
Activity related to the ARO liability for the years ended December 31, 2011 and 2010 is as follows (in thousands):
The liability comprises a current balance of approximately $3.2 million and $2.9 million and a noncurrent balance of approximately $41.4 million and $37.4 million as of December 31, 2011 and 2010, respectively.
Revisions to asset retirement obligations reflect changes in abandonment cost estimates, and reserve lives based on current information and considering the Company’s current plans.
6. DERIVATIVE FINANCIAL INSTRUMENTS
The Company produces and sells oil, natural gas and natural gas liquids. As a result, its operating results can be significantly affected by fluctuations in commodity prices caused by changing market forces. The Company periodically seeks to reduce its exposure to price volatility of a portion of its production by acquiring swaps, options and other commodity derivative financial instruments. A combination of options, structured as a collar, is the Company’s preferred derivative instrument because there are no up-front costs and protection is provided against low prices. Such derivatives provide assurance that the Company receives NYMEX prices no lower than the price floor and no higher than the price ceiling. For the year ended December 31, 2011, the Company had over 1.5 MMBOE , or roughly 53% of production, hedged through a series of gas collars, gas swaps and oil collars. As of December 31, 2011, the Company has approximately 1.8 MMBOE of production hedged for 2012 which relates to approximately 74.1% of projected production.
All derivative contracts are recorded at fair market value and included in the consolidated balance sheets as assets or liabilities. The following table summarizes the location and fair value of all derivative financial instruments in the consolidated balance sheets as of December 31, 2011 and 2010 (in thousands):
The following table summarizes the locations and amounts of the Company’s realized and unrealized gains and losses on derivative contracts in the Company’s consolidated statements of operations:
At December 31, 2011, the Company had the following natural gas collar positions:
At December 31, 2011, the Company had the following natural gas swap positions:
At December 31, 2011, the Company had the following crude oil collar positions:
At December 31, 2011, the Company had the following crude oil swap positions:
At December 31, 2011, the Company had the following NGL swap positions:
As of December 31, 2011, the Company had no active interest rate collar positions.
7. FAIR VALUES OF FINANCIAL INSTRUMENTS
The table below presents information about the Company’s financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2011 and December 31, 2010, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value.
In general, fair values determined by Level 1 inputs utilize quoted prices (unadjusted) in active markets the Company has the ability to access for identical assets or liabilities. Fair values determined by Level 2 inputs utilize inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar assets and liabilities in active markets and inputs other than quoted prices observable for the asset or liability, such as interest rates and yield curves observable at commonly quoted intervals. 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. In instances in which the inputs used to measure fair value may fall into different levels of the fair value hierarchy, the level in the fair value hierarchy within which the fair value measurement in its entirety has been determined is based on the lowest level input significant to the fair value measurement in its entirety. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. Disclosures concerning financial assets and liabilities measured at fair value are as follows:
(a) Represents the effects of reclassification of the assets and liabilities to conform to the balance sheet presentation.
To obtain fair values, observable market prices are used if available. In some instances, observable market prices are not readily available for certain financial instruments and fair value is determined using present value or other techniques appropriate for a particular financial instrument using observable inputs (such as forward commodity price and interest rate curves). These techniques involve some degree of judgment and as a result are not necessarily indicative of the amounts the Company would realize in a current market exchange. The use of different assumptions or estimation techniques may have a material effect on the estimated fair value amounts.
Derivative Financial Instruments - The majority of the inputs used to value the Company’s derivatives fall within Level 2 of the fair value hierarchy; however, the credit valuation adjustments associated with these derivatives utilize Level 3 inputs, such as estimates of current credit spreads to evaluate the likelihood of nonperformance. As of December 31, 2011 and December 31, 2010, the impact of the credit valuation adjustments on the overall valuation of the Company derivative positions is not significant to the overall valuation. As a result, derivative valuations in their entirety are classified in Level 2 of the fair value hierarchy.
Debt Instruments - The 2011 First Lien Credit Agreement accrues (as defined in Note 8) interest on a variable-rate basis. The Notes (as defined in Note 8) accrue interest on a fixed rate basis. As of December 31, 2011, the fair value of the 2011 Credit Facility was estimated (based on market rates currently available to the Company) to be approximately $132.8 million. As of the same date, the fair value of the Notes was estimated (based upon market prices), to be approximately $200.8 million. As of December 31, 2010, all of the Company’s debt instruments, with the exception of the Series A Preferred Stock, accrue interest on a variable-rate basis. The Company estimates the carrying values in Note 8 to represent an approximation to its fair value based on the terms of similar instruments that would be available to the Company.
Cash and Cash Equivalents, Trade Receivables, and Payables - The fair value approximates carrying value given the short-term nature of these investments.
8. DEBT
The Company’s debt as of December 31, 2011 and 2010 was comprised of the following amounts (in thousands):
Scheduled maturities by fiscal year are as follows (amounts in thousands):
As described in more detail below, in May 2011, we completed an offering of an aggregate of $250 million of the Notes. We used the proceeds of this offering, together with borrowings under First Lien Agreement, to refinance substantially all of our existing indebtedness (the “2011 Refinancing”). The weighted average interest rate at December 31, 2011 was 8.13% as compared to the weighted average interest rate at December 31, 2010 of 8.97%.
First Lien Credit - Prior to the 2011 Refinancing, our first lien credit agreement (the “Prior First Lien Agreement”) among Milagro Exploration, LLC and Milagro Producing, LLC, each an indirect wholly-owned subsidiary of the Company (collectively, the “Borrowers”), the Company, each of the lenders from time to time party thereto and Wells Fargo Bank, N.A. as administrative agent for the lenders, provided for a borrowing base of $179 million. The borrowing base was determined semi-annually using the estimated value of the Company’s oil and natural gas properties.
Amounts outstanding under the Prior First Lien Agreement bore interest at specified margins over LIBOR of between 3.00% and 3.75% for Eurodollar loans or at specified margins over the ABR of between 2.00% and 2.75% for ABR loans. Such margins fluctuated based on the utilization of the facility. As of December 31, 2010, the LIBOR based interest rate was 4.04% and the base-rate interest rate was 6.00%. Borrowings under the Prior First Lien Agreement were secured by all of the Company’s oil and natural gas properties. The lenders’ commitments to extend credit were scheduled to expire, and amounts drawn under the Prior First Lien Agreement would have matured, in November 2011.
As part of the 2011 Refinancing, the Company entered into the $300 million 2011 Credit Facility, that matures in November 2014. The 2011 Credit Facility also includes a $10 million subfacility for standby letters of credit, of which approximately $1.6 million has been issued as of December 31, 2011, and a discretionary swing line subfacility of $5 million. The initial borrowing base for this facility was established at $170 million with semi-annual re-determinations beginning in November 2011. In November 2011, as a result of the scheduled borrowing base redetermination, the borrowing base was increased by $10 million to $180 million. Amounts outstanding, under the 2011 Credit Facility bear interest at specified margins over the LIBOR of between 2.75% and 3.75% for Eurodollar loans or at specified margins over the ABR of between 1.75% and 2.75% for ABR loans. Such margins will fluctuate based on the utilization of the facility. As of December 31, 2011, the LIBOR based interest rates ranged from 3.89% to 4.00 %. Borrowings under the 2011 Credit Facility are secured by all of the Company’s oil and natural gas properties. The lenders’ commitments to extend credit will expire, and amounts drawn under the 2011 Credit Facility will mature, in November 2014.
The 2011 Credit Facility contains customary financial and other covenants, including minimum working capital levels (the ratio of current assets plus the unused availability of the borrowing base under the 2011 Credit Facility to current liabilities) of not less than 1.0 to 1.0 (which was 1.85 as of December 31, 2011), minimum interest coverage ratio, as defined, of not less than 2.25 to 1.0 (which was 3.47 as of December 31, 2011), maximum leverage ratio, as defined, of debt balances as compared to EBITDA of not greater than 4.5 to 1.00 (which was 3.98 as of December 31, 2011) and maximum senior secured leverage ratio, as defined, of senior secured debt balances as compared to EBITDA of not greater than 2.0 to 1.0 (which was 1.45 as of December 31, 2011). The interest coverage ratio increases from 2.25 to 1.0 at December 31, 2011 and 2.5 to 1.0 thereafter. The leverage ratio, as defined, is 4.5 to 1.0 for 2011. The leverage ratio for the first quarter of 2012 was waived and then will reduce to 4.25 to 1.0 for the remainder of 2012 and 4.0 to 1.0 thereafter. In addition, the Company is subject to covenants limiting all dividends and other restricted payments, transactions with affiliates, incurrence of debt and liens, changes of control and asset sales. As of December 31, 2011, the Company is in compliance with the financial covenants governing the 2011 Credit Facility.
Series A Preferred Stock - As part of the 2010 recapitalization, the Company entered into agreements to exchange a portion of prior second lien indebtedness for $205.5 million of Series A Preferred Stock (the “Series A”), consisting of 2,700,000 shares issued at $76.12 per share, mandatorily redeemable in 2016. The preferred shareholders receive a 12% dividend each year paid in-kind. There were no dividends paid during the years ended December 31, 2011, 2010 or 2009, respectively. There was an increase of approximately $10.3 million of Series A from December 31, 2010 to May 11, 2011, which was primarily related to the accrual of the in-kind dividend that was recorded as interest expense. Upon completion of the 2011 Refinancing, including the amendment of the terms of the Series A as described in Note 10, the Series A was reclassified as mezzanine equity for financial reporting purposes because there is no longer a mandatory redemption provision.
Capitalization of Debt Costs - The Company capitalizes certain direct costs associated with the issuance of long-term debt, which is then amortized over the lives of the respective debt using the straight-line method, which approximates the interest method. As of December 31, 2011 and December 31, 2010, the Company had deferred financing fees of $7.9 million and $1.8 million, respectively.
The Company capitalizes a portion of its interest expense incurred during the period related to assets that have been excluded from the amortization pool. For the years ended December 31, 2011, 2010 and 2009, the Company capitalized interest of $1.2 million, $2.4 million and $4.6 million, respectively.
Senior Secured Second Lien Notes - As part of the 2011 Refinancing, the Company issued Senior Secured Second Lien Notes due May 11, 2016 with a face value of $250 million, at a discount of $7 million (the “Notes”). The Notes carry a stated interest rate of 10.500%, interest is payable semi-annually each May 15 and November 15. The Notes are secured by a second priority lien on all of the collateral securing the 2011 Credit Facility, and effectively rank junior to any existing and future first lien secured indebtedness of the Company. The outstanding balance of the Notes is presented net of unamortized discount at December 31, 2011.
The Notes contain an optional redemption provision allowing the Company to retire up to 35% of the principal outstanding, with the proceeds of an equity offering, at 110.5% of par. Additional optional redemption provisions allow for the retirement of all or a portion of the outstanding senior secured second lien notes at 110.5%, 102.625% and 100.0% beginning on each of May 15, 2014, May 15, 2015 and November 15, 2016, respectively. If a change of control occurs, each noteholder may require the Company to repurchase all or a portion of its notes for cash at a price equal to 101% of the aggregate principal amount of such notes, plus any accrued and unpaid interest and special interest, if any, to, but not including, the date of repurchase. The indenture governing the Notes contains covenants that, among other things, limit the Company’s ability to incur or guarantee additional indebtedness or issue certain preferred stock; declare or pay any dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; transfer or sell assets; make investments; create certain liens; consolidate, merge or transfer all or substantially all of its assets; engage in transactions with affiliates; and create unrestricted subsidiaries.
9. GUARANTOR AND NON-GUARANTOR
The Company is not required to disclose condensed consolidating financial information as the parent company has no independent assets or operations and owns 100% of each of the Borrowers, Milagro Resources, LLC and Milagro Mid-Continent, LLC. The subsidiary guarantees are full and unconditional guarantees of the Company’s outstanding debt on a joint and several basis. There are no non-guarantor subsidiaries. These subsidiaries are included in the consolidated financial statements.
10. MEZZANINE EQUITY
In connection with the 2011 Refinancing, the Company amended the terms of the Series A. Prior to the amendment, the Series A was treated as debt for accounting purposes, as there was a mandatory redemption date. The amendment made the Series A a perpetual instrument and provides the holders with an option to redeem the preferred shares. The amendment also requires two-thirds (2/3) of the holders to request redemption, 180 days after the maturity of certain qualified debt which matures in 2016, with the redemption date being not more than 90 days after receiving the redemption request. Therefore, as a result of the amendment, the Series A was reclassified from long-term debt to mezzanine equity.
The holders of the Series A shall be entitled to receive dividends on a cumulative basis. Dividends shall accrue, whether declared or not, semi-annually at a 12% rate. Accrued dividends shall be paid in kind when, and if declared by the Company’s board of directors and shall be made by issuing an amount of additional shares of Series A based on the original issue price. As of December 31, 2011, the dividends in arrears were $18.6 million.
The estimated fair value of the Series A at December 31, 2011 was approximately $183 million.
11. COMMON STOCK
The Company is authorized to issue up to 1,000,000 shares of Common Stock, par value $0.01 per share. As of December 31, 2011 and 2010, 280,400 shares of Common Stock were issued and outstanding and held by Parent. Holders of Common Stock are entitled to, in the event of liquidation, to share ratably in the distribution of assets remaining after payment of liabilities. Holders of Common Stock have no cumulative rights. Holders of Common Stock have no preemptive or other rights to subscribe for shares. Holders of Common Stock are entitled to such dividends as may be declared by the board of directors of the Company out of funds legally available therefore. The Company has never paid cash dividends on the Common Stock and does not anticipate paying any cash dividends in the foreseeable future.
12. INCOME TAXES
The income tax expense (benefit) in the Company’s consolidated statements of operations consisted of the following:
The differences between income taxes computed using the statutory federal income tax rate and that shown in the statement of operations are summarized as follows:
Significant components of the Company’s deferred tax assets as of December 31, 2011 and 2010 are as follows:
In determining the carrying value of a deferred tax asset, accounting standards provide for the weighing of evidence in estimating whether and how much of a deferred tax asset may be recoverable. As the Company has incurred net operating losses in all years, relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence, and that future expectations about income are insufficient to overcome a history of such losses. Therefore, we have reduced the carrying value of our net deferred tax asset to zero. The valuation allowance has no impact on our NOL position for tax purposes, and if we generate taxable income in future periods, we will be able to use the NOL’s to offset taxes due at that time. The tax asset related to the NOLs of $14.8 million will begin to expire in 2030. The Company will continue to assess the valuation allowance against deferred tax assets considering all available evidence obtained in future reporting periods.
13. COMMITMENTS AND CONTINGENCIES
Commitments - The Company leases corporate office space in Houston, Texas. Rental expense was approximately $1.8 million, $2.1 million and $2.4 million for the years ended December 31, 2011, 2010 and 2009, respectively.
In 2009, the Company entered into a contract with an investment bank for advisory services to be provided in 2010 for guaranteed fees of $1.0 million, this contract has been extended to 2013. The Company paid $0.3 million in fees out of the $1.0 million to the investment bank in connection with the 2011 Refinancing.
The following table summarizes the Company’s contractual obligations and commitments at December 31, 2011, by fiscal year (amounts in thousands):
Contingencies:
There are currently various suits and claims pending against the Company that have arisen in the ordinary course of the Company’s business, including contract disputes, property damage claims and title disputes. Management believes that the resolution of these suits and claims will not, individually or in the aggregate, have a material effect on the Company’s consolidated financial position, results of operations or cash flow. The Company records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.
14. EMPLOYEE BENEFIT PLANS
The Company operates a discretionary bonus plan and a 401(k) savings plan via a third-party service provider.
Upon hire, an individual is immediately eligible to participate in the 401(k) plan. The Company, under its sole discretion, may contribute an employer-matching contribution equal to a percentage not to exceed 6% of each eligible participant’s contributions. The Company contributed $592,000, $283,000, and $356,000, in the years ended December 31, 2011, 2010 and 2009, respectively.
15. RELATED PARTY TRANSACTIONS
As of December 31, 2011 and 2010, the Company had a receivable of $2.4 and $2.2 million, respectively, for monitoring fees on behalf of Parent to Parent’s members, ACON Milagro Investors, LLC, Milagro Investors, LLC and West Coast Milagro Partners, LLC, in 2008 and 2007, which are recognized as an advance to affiliates in the accompanying balance sheets.
16. SEGMENT INFORMATION
Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses. Separate financial information is available and this information is regularly evaluated by the chief decision maker for the purpose of allocating resources and assessing performance.
The Company measures financial performance as a single enterprise, allocating capital resources on a project by project basis across its entire asset base to maximize profitability. The Company utilizes a company-wide management team that administers all enterprise operations encompassing the exploration, development and production of natural gas and oil. Since the Company follows the full cost of method of accounting and all its oil and natural gas properties and operations are located in the United States, the Company has determined that it has one reporting unit. In as much as the Company is one enterprise, it does not maintain comprehensive financial statement information by area but does track basic operational data by area.
MILAGRO OIL & GAS, INC.
SUPPLEMENTAL DISCLOSURES ABOUT OIL & GAS PRODUCING ACTIVITIES
1. Modernization of Oil and Natural Gas Reporting Requirements
The reserve estimates as of December 31, 2011, 2010 and 2009, presented herein were made in accordance with oil and natural gas reserve estimation and disclosure authoritative accounting guidance issued by the Financial Accounting Standards Board effective for reporting periods ending on or after December 31, 2009. This guidance was issued to align the accounting oil and natural gas reserve estimation and disclosure requirements with the requirements in the SEC’s “Modernization of Oil and Gas Reporting” rule, which was also effective for annual reports for fiscal years ending on or after December 31, 2009.
The above-mentioned rules include updated definitions of proved oil and natural gas reserves, proved undeveloped oil and natural gas reserves, oil and natural gas producing activities, and other terms used in estimating proved oil and natural gas reserves. Proved oil and natural gas reserves as of December 31, 2011, 2010 and 2009 were calculated based on the prices for oil and natural gas during the twelve month period before the reporting date, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. The authoritative guidance broadened the types of technologies that a company may use to establish reserve estimates and also broadened the definition of oil and natural gas producing activities to include the extraction of non-traditional resources, including bitumen extracted from oil sands as well as oil and natural gas extracted from shales.
2. Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
Costs incurred in the acquisition and development of oil and natural gas assets are presented below for the years ended December 31:
(1) Includes asset retirement obligations incurred and revisions of previous estimates of $3.3 million, $10.1 million and $(9.9) million for 2011, 2010 and 2009, respectively.
3. Capitalized Oil and Natural Gas Costs
Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are presented below as of December 31:
Unproved properties, which are not subject to amortization, are not individually significant and consist primarily of lease acquisition costs. The evaluation process associated with these properties has not been completed and therefore, the Company is unable to estimate when these costs will be included in the amortization calculation.
4. Proved Oil and Natural Gas Reserves
The Company’s proved oil and natural gas reserves were prepared by W.D Von Gonten & Co. (W.D. Von Gonten), independent third party petroleum consultants. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, the estimates may change as future information becomes available.
An analysis of the change in estimated quantities of oil and natural gas reserves, all of which are located within the United States, for the years ended December 31, is as follows:
Milagro Oil & Gas, Inc
Supplemental Oil and Gas Disclosures
The tables above include changes in estimated quantities of oil and natural gas reserves shown in Bbl equivalents (“Boe”) at a rate of six Mcf per one Bbls.
For the year ended December 31, 2011, the Company added 2.79 MMBoe through acquisitions in its onshore Texas Gulf Coast and Midcontinent core areas, with a negative revision of 1.5 MMBoe of previous estimated quantities primarily due to certain natural gas proved undeveloped locations being dropped from the Company’s plan due to the low natural gas prices. The oil and natural gas reference prices used in computing reserves as of December 31, 2011 were $96.19 per barrel and $4.12 per Mmbtu before price differentials.
For the year ended December 31, 2010, the Company added 7.6 MMBoe through acquisitions in its core areas of onshore Texas Gulf Coast and the Midcontinent, with a positive revision of 1.3 MMBoe of previous estimated quantities primarily due to an increase in reference prices. The oil and natural gas reference prices used in computing reserves as of December 31, 2010 were $79.43 per barrel and $4.38 per Mmbtu before price differentials.
For the year ended December 31, 2009, extensions of 1.4 MMBoe during the year ended December 31, 2009, consist primarily from adding of seven proved undeveloped locations. Divestures of 1.3 MMBoe were made throughout 2009. The oil and natural gas reference prices used in computing reserves as of December 31, 2009 were $61.18 per barrel and $3.87 per MMbtu before price differentials.
5. Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions.
The estimates of future cash flows and future production and development costs as of December 31, 2011, 2010 and 2009 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Prices were adjusted by lease for quality, transportation fees and regional price differentials. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. Future income tax expenses are computed using the appropriate year-end statutory tax rates applied to the future pretax net cash flows from proved oil and natural gas reserves, less the tax basis of the Company. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%.
It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the Company’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves. Estimates of economically recoverable oil and natural gas reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil and natural gas may differ materially from the amounts estimated.
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves as of December 31, 2011, 2010 and 2009 is as follows:
The changes in standardized measure as of December 31, 2011, 2010 and 2009 are as follows:
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures
Not Applicable
Item 9A.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, our management, including our Chief Executive Officer and Vice President of Finance and Chief Accounting Officer, completed an evaluation of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities and Exchange Act of 1934, as amended, and determined that our disclosure controls and procedures were not effective as of December 31, 2011. We have identified certain material weaknesses in our internal control over financial reporting related to preparation and insufficient financial reporting resources in our internal control over financial reporting primarily related to a lack of financial and personnel resources allocated to our information technology general controls. To remediate these issues, our management intends to retain the services of additional third party accounting personnel as well as to modify existing internal controls in a manner designed to ensure future compliance. Our management currently believes the additional accounting resources expected to be retained for purposes of becoming a SEC reporting company will remediate the weakness with respect to insufficient personnel.
Management’s Annual Report on Internal Control over Financial Reporting and Attestation Report of Registered Public Accounting Firm
This annual report does not include a report of management’s assessment regarding internal control over financial reporting of our registered public accounting firm due to a transition period established by rules of the SEC for newly public companies.
Changes in Internal Control Over Financial Reporting
There have been no changes in our internal control over financial reporting during the annual period covered by this report that have materially affected, or that are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B.
Item 9B. Other Information
Not Applicable
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
Officers and Directors
The following is a list of our executive officers and directors as of December 31, 2011. Our directors hold office until the expiration of their term or until their successors are duly elected and qualified.
James G. Ivey has served as our President and Chief Executive Officer, and has served on our board of directors, since January 2011. Prior to this he served as Executive Vice President and Chief Financial Officer from 2009 through 2010. Prior to joining us, Mr. Ivey served as Executive Vice President and Chief Financial Officer of Cobalt International Energy, L.P. from 2006 through 2008, Chief Financial Officer of MarkWest Hydrocarbon, Inc. from 2004 to 2006, and as Treasurer and Acting Chief Financial Officer of The Williams Company from 1995 through 2004, and as Treasurer for Tenneco Gas and Arkla, Inc. from 1989 through 1994. Mr. Ivey began his career as an engineer, first with Fluor Corp. and later with Conoco, Inc. He earned his undergraduate degree from Texas A&M University and his MBA from the University of Houston. He is also a graduate of the Army Command and General Staff College and the Duke University Advanced Management Program. Mr. Ivey has served on the Board of Directors of Milagro Exploration since 2011. Mr. Ivey also serves on the boards of MachGen, LLC, an operator of gas-fired generation plants, and National Energy & Gas Transmission, Inc.
Gary Mabie has served as our Chief Operating Officer since February 2010. Prior to joining us, Mr. Mabie worked as President for GM Oil & Gas Company, an industry provider of consulting services, Vice President of Operations at Comet Ridge Resources from 2006 to 2009, President of CDX West, a subsidiary of CDX Gas, LLC, from 2005 to 2006, President and Chief Operating Officer of SunCoast Energy Corporation from 2000 to 2005, General Manager and Senior Vice President of Onshore of Pennzoil/PennzEnergy from 1997 to 1999, and Vice President of Exploration and Production for Hunt Petroleum from 1990 to 1997. Mr. Mabie served in various management positions with Tenneco Oil, E&P with the last position being Operations Manager of the International Division. Mr. Mabie began his career as a petroleum engineer with Gulf Oil Corporation. He graduated from Texas A&M University with a Bachelor of Science degree in Petroleum Engineering.
Marshall Munsell is one of our original founders and as our Senior Vice President of Business Development has been responsible for our Land and Business Development departments since our formation in 2005. Prior to joining us, Mr. Munsell worked for Mission Resources Corporation as Senior Vice President of Land and Land Administration from 2002 to 2005, and has served in various management and staff roles with DDD Energy, Presidio Oil Company and Sun Oil Company. Mr. Munsell is a Certified Professional Landman and earned his Bachelor’s degree in Petroleum Land Management from the University of Texas.
Tom Langford is one of our original founders and is our Senior Vice President and General Counsel responsible for our Legal, Environmental and Human Resources departments since our formation in 2005. Prior to joining us, Mr. Langford worked as Senior Vice President and General Counsel for Mission Resources Corporation from 2004 to 2005, and Vice President and General Counsel of El Paso Production Company from 1999 to 2004. Mr. Langford earned his BA from Stephen F. Austin University and graduated from South Texas College of Law.
Robert LaRocque has served as our Vice President of Finance and Treasurer since October 2010. Prior to joining us, Mr. LaRocque served as a Managing Director for Credit Lyonnais from 1997 to 2003, Vice President of Corporate Development for Aquila Energy from 1995 to 1997 and Director of International Finance at Tenneco Gas. Mr. LaRocque earned his undergraduate degree from Queen’s University and his MBA from Dalhousie University.
Lloyd Armstrong has served as our Vice President of Production Logistics since January 2008. Prior to joining us, Mr. Armstrong served as Vice President of Operational Accounting for Goodrich Petroleum Corporation from August 2005 until December 2007, Vice President of Revenue Administration for Mission Resources Corporation from November 2002 to July 2005 and as Director of Operational Accounting for El Paso Production Company from 1999 to 2002. Mr. Armstrong has also served as Accounting Manager for El Paso Field Services and as Project Manager of a gas plant accounting system implementation for Andersen Consulting from 1997 to 1998. Mr. Armstrong began his career at Amerada Hess Corporation where he held several accounting positions from 1980 to 1997. Mr. Armstrong earned his BS in Accounting and Business Administration from Northeastern State University in Oklahoma.
Mark Stirl has served as our Vice President and Controller since December 2007. Prior to joining us, Mr. Stirl served as the Vice President and Controller of Peoples Energy Production Company from 2006 to 2007. He also held various accounting and finance positions at BHP Billiton from 2004 to 2006, worked for Dunhill Resources as their Controller during 2003, and worked for CMS Oil and Gas as their Vice President and Controller 1997 to 2002. Mr. Stirl worked for Sonat Exploration Company from 1980 through 1997 in various accounting and financial functions, and as their Controller the last seven years of his service. Mr. Stirl began his career in public accounting working for Melton and Melton, CPAs. He received both a BSBA degree in Accounting and a MBA degree in Finance from the University of Houston.
Jonathan Ginns is a Founder and Managing Partner of ACON Investments and has served on our board of directors since 2007. Founded in 1996, ACON is an international private equity investment firm managing capital through varied investment funds and special purpose partnerships. Prior to founding ACON, he was a Senior Investment Officer at the GEF Funds Group. Previously, Mr. Ginns was a Management Consultant at Booz Allen & Hamilton. Mr. Ginns received an MBA from the Harvard Business School, and a BA from Brandeis University. He also serves on the Boards of Directors of Chroma Oil & Gas, Northern Tier Energy and Signal International.
Mo Bawa is a Principal of ACON Investments and has served on our board of directors since 2007. He is responsible for sourcing, evaluating, executing and monitoring transactions principally in the energy sector for ACON. Previously, he was an Associate with Constellation Commodities Group where he was responsible for origination, structuring, evaluation, and negotiation of the firm’s principal investments. Mr. Bawa has also held corporate finance and principal investing positions with Houlihan Lokey Howard & Zukin, Enron Capital & Trade Resources, and Banc of America Securities. Mr. Bawa holds a B.A. in Economics, Management and Public Policy from Rice University and MBA from The Anderson School at UCLA. He also serves on the Boards of Directors of Chroma Oil & Gas and Signal International.
Thomas J. Hauser is a Director of Guggenheim Partners, LLC and has served on our board of directors since April 11, 2011. Guggenheim is an asset management firm with over $120 billion of assets under management. Mr. Hauser joined Guggenheim in 2002 as an analyst on the leveraged credit investing team. During his tenure at Guggenheim, he has covered multiple industries including gaming, leisure, transportation, utilities, energy and real estate. He currently leads an industry team that focuses on investing across the capital structure in the energy, power and transportation sectors. Mr. Hauser earned his Bachelor of Science degree in Finance from St. John’s University and is a member of the Association for Corporate Growth.
Adam Cohn is a Principal at Knowledge Universe Limited, LLC where he has worked since 2000 and has served on our board of directors since 2007, as a representative of West Coast Energy Partners. Prior to Knowledge Universe, Mr. Cohn worked at Whitney & Co., a private equity firm. Prior to Whitney & Co., Mr. Cohn was an investment banker in the Financial Sponsors Group at Bankers Trust Company and Deutsche Bank. He has a Bachelor’s Degree in Business from Skidmore College and a MBA from Columbia University. He also serves on the boards of Knowledge Learning Corporation, Busy Bees Holdings Limited, and Embanet-Compass Knowledge Group Inc.
Board of Directors
Our board of directors is composed of five members, each of whom is elected annually by our stockholders. Under the Stockholders’ Agreement dated January 13, 2010, as subsequently amended (the “Stockholders’ Agreement”), which is effective for so long as we are a subsidiary of our parent company, Holdings, holders of our Series A preferred stock have the right to appoint four of the five members of our board of directors.
Messrs. Bawa and Ginns are appointees of ACON, Mr. Hauser is an appointee of Guggenheim and Mr. Cohn is an appointee of West Coast Energy. Our fifth director is our chief executive officer.
Currently, our only board committee is the audit committee, the members of which are Mo Bawa (who also serves as chairman) and Thomas Hauser. We do not have a compensation or corporate governance and nominating committee, as our full board performs the functions typically designated to these committees. As we are not a “listed issuer” within the meaning of Rule 10A-3 of the Exchange Act, we are not subject to the requirements of such rule. Neither member of the audit committee meets the requirements of an “audit committee financial expert” as defined in the rules of the SEC, nor does any other member of our board of directors. Given the makeup of our board of directors and the fact that we have only one holder of our common stock, we do not believe it is necessary to have a person who meets such requirements serving on the audit committee.
Compliance with Section 16(a) of the Exchange Act
Not applicable
Code of Ethics
We have adopted a code of ethics that applies to all of our employees, as well as each member of our board of directors. A copy of the code of ethics will be provided, without charge, upon written request to Milagro Oil & Gas, Inc., Attention: Human Resources, 1301 McKinney, Suite 500, Houston, Texas 77010, phone: 713-750-1600. We intend to post amendments to or waivers from the code of ethics (to the extent applicable to our principal executive officer, principal financial officer or principal accounting officer) on our website.
Item 11.
Item 11. Executive Compensation
Compensation Discussion and Analysis
General
The following discussion describes and analyzes our compensation for our named executive officers for 2011, which include our principal executive officer, principal financial officer, and the three most highly compensated executive officers other than the principal executive and principal financial officers as set forth in the “Summary Compensation Table” below, or our “named executive officers.”
We are an independent oil and gas company primarily engaged in the acquisition, exploitation, development and production of oil and natural gas reserves. We were formed as a limited liability company in 2005 with a focus on properties located onshore in the U.S. Gulf Coast. In November 2007, we acquired the Gulf Coast assets of Petrohawk Energy Corporation for approximately $825.0 million. The acquisition included properties primarily in the onshore Gulf Coast region in Texas, Louisiana and Mississippi. Since this acquisition, we have acquired additional proved producing reserves that we believe have upside potential, implemented an active drilling, workover and recompletion program and expanded our geographic diversity by moving into the Midcontinent region.
Compensation Philosophy and Objectives and Elements of Compensation
Our intent and philosophy in designing compensation packages at the time of hiring new executives has been based in part on providing compensation that we thought was sufficient to enable us to attract the talent necessary to further develop our business while at the same time being prudent in the management of our cash and equity. Compensation of our executive officers after the initial period following their hiring has been influenced by the amounts of compensation that we initially agreed to pay them as well as by our evaluation of their subsequent performance, changes in their levels of responsibility, prevailing market conditions, our financial condition and prospects.
We have compensated our executives with a combination of salaries, cash bonuses and awards under our profits interest plan, or the Plan. We also believe that it provides an appropriate blend of compensation to retain our executives, reward them for performance in the short term and induce them to contribute to the creation of value in the Company over the long term.
We view the different components of our executive compensation as distinct. We believe we must maintain a sufficiently competitive salary to position us to attract the executives that we need and that it is important that our executives perceive that over time they will continue to have the opportunity to earn a salary that they regard as competitive.
The ability to earn cash bonuses should incentivize executives to effectively pursue goals established by our board of directors and should be regarded by executives as appropriately rewarding effective performance against these goals. In the past we have sought to establish target bonus levels and performance goals for executives at the beginning of the year to help ensure that our performance goals, and the bonus attainable for achieving these goals, were well understood by executives.
The Plan is a profits interest incentive program in which we issue to employees profits interests in a limited partnership which owns Class C membership interests in our parent company, Holdings, which is a holding company and the holder of record of 100% of our issued and outstanding common stock. The participants’ profits interests represent the right to receive a percentage of the distributions made by Holdings when such distributions exceed specified internal rate of return thresholds. This Plan is designed to recognize the need for current profitability as well as building long-term value. In addition, the Plan is designed to aid us in retaining the services of key executives and employees by requiring vesting conditions on each grant, which provide that the participant would forfeit the unvested portion of the grant upon their termination of service with us. Vested units may also be forfeited in certain circumstances, including certain termination events, a personal bankruptcy or other specified conditions.
We have used awards under the Plan as the form of equity award for executives. The size of the award is determined based on the executive’s position with us and takes into consideration the executive’s base salary and other compensation as well as an analysis of the grant and compensation practices of other companies in our industry. Typically, our Plan awards to executive officers vest and become exercisable over five years. Our board of directors believes that these awards align the interests of our named executive officers with those of the stockholders, because they create the incentive to build stockholder value over the long-term. In addition, our board of directors believes the vesting provision of our equity awards improves our ability to retain our executives.
Compensation Decision Process
Since our formation, our board of directors has overseen the compensation of our executive officers and our executive compensation programs and initiatives. While we have had an Executive Compensation Committee which administers the Plan, the ultimate compensation decisions have been made by the full board of directors. The board of directors has also sought, and received, significant input from our principal executive officer with regard to the performance and compensation of executives other than himself.
Certain of our directors have significant experience with privately held private equity-backed companies such as ours and the executive compensation practices of such companies, and have applied this knowledge and experience to their judgments regarding our compensation decisions.
2011 Compensation
Salary
The salaries of our named executive officers are reflected below and were determined by our board of directors. Compensation is reviewed annually against salaries being paid by other companies of a like size and scope.
Bonus
Bonus compensation is based on the discretion of our board of directors and upon achievement of performance objectives established by our board of directors annually. Criteria making up the bonus objectives in 2011 included a weighting of the following criteria: annual EBITDA, total production expressed on a per Bcfe basis, reserve replacement, lease operating expense expressed on a per Mcfe basis and gross general and administrative expenses. These criteria were chosen, in the case of EBITDA, lease operating expense and gross general and administrative expense, as the most significant measure of our cash flows and profitability, and, in the case of total production and reserve replacement, as the most significant measures of success during the year in our business. Each category has an annual threshold of 75% of the approved budget, a target of 100% of the approved budget and a stretch goal of 125% of the approved budget. We believe that all goals, while intentionally presenting a significant challenge, are realistic and achievable by our executives in most instances, if they perform their duties with the degree of care and diligence that we expect of them.
Target, threshold and stretch criteria in the table below were established by our board of directors and are the same for each of the named executive officers
Severance and Change of Control Agreements
We have entered into employment letters with certain of our named executive officers providing for certain payments upon termination of their employment with us without cause and upon termination without cause following a change of control. These payments, and the definition for this purpose of change of control, are described in detail below under “Potential Payments upon Termination and Change in Control.”
We believe that these agreements appropriately balance our needs to offer a competitive level of severance protection to our executives and to induce our executives to remain in our employ through the potentially disruptive conditions that may exist around the time of a change in control, while not unduly rewarding executives for a termination of their employment. We note that our change in control terms include so-called “double trigger” provisions, so that the executive is not entitled to the severance payment by the mere occurrence of the change in control. We believe this feature will be an incentive to the executive to remain in our employ if such continuation is required by our partner in a change in control transaction. We also believe that it is appropriate that our executives’ equity awards be treated, in the event of a change of control, like those of other employees and not accelerated if the executive’s employment continues following the change in control event.
Other Executive Benefits and Perquisites
We provide the following benefits to our executive officers on the same basis as other eligible employees:
•
health insurance;
•
vacation, personal holidays and sick days;
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life insurance and personal accident insurance;
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short-term and long-term disability; and
•
a 401(k) plan.
We believe these benefits are generally consistent with those offered by other companies with which we compete for executive talent.
Other Compensation Practices and Policies
Policy regarding the timing of equity awards. As a privately-owned company, there is no market for our capital stock. Accordingly, in fiscal year 2011, we had no program, plan or practice pertaining to the timing of stock option grants to executive officers coinciding with the release of material non-public information. We do not, as of yet, have any plans to implement such a program, plan or practice.
Policy regarding restatements. We do not have a formal policy regarding adjustment or recovery of awards or payments if the relevant performance measures upon which they are based are restated or otherwise adjusted in a manner that would reduce the size of the award or payment. Under those circumstances, our board of directors or a committee thereof, would evaluate whether adjustments or recoveries of awards were appropriate based upon the facts and circumstances surrounding the restatement.
Stock Ownership Policies. We have not established stock ownership or similar guidelines with regards to our executive officers. All of our executive officers currently have an indirect equity interest in our company through their Plan awards and we believe that they regard the potential returns from these interests as a significant element of their potential compensation for services to us.
Summary Compensation Table
The following table summarizes the compensation earned by our principal executive officer, principal financial officer and each of our three other most highly compensated executive officers during the year ended December 31, 2011.
2011 Summary Compensation Table
The following table provides information concerning compensation paid or accrued during the fiscal years ended December 31, 2011, 2010 and 2009 to our principal executive officer and our two other executive officers, including our principal financial officer, determined at the end of the last fiscal year, and one former executive officer for whom disclosure would have been required but for the fact that he was not serving as an executive officer at the end of the fiscal year ended December 31, 2011:
(1) The participant’s profits interests under the Plan represent the right to receive a percentage of the distribution made by Holdings when such distributions exceed specified internal rate of return thresholds. Those thresholds had not been met as of December 31, 2011.
(2) Represents reimbursement of housing and commuting expenses.
Grants of Plan-Based Awards Table
The following table shows information regarding grants of equity awards to our named executive officers during the year ended December 31, 2011.
2011 GRANTS OF PLAN-BASED AWARDS TABLE
(1) The participant’s profits interests under the Plan represent the right to receive a percentage of the distribution made by Holdings when such distributions exceed specified internal rate of return thresholds. Those thresholds had not been met as of December 31, 2011.
Outstanding Equity Awards at Fiscal Year-End
The following table shows the grants of equity awards to our named executive officers that were outstanding on December 31, 2011, the last day of our fiscal year.
OUTSTANDING EQUITY AWARDS AT 2011 FISCAL YEAR-END
(1) The participant’s profits interests under the Plan represent the right to receive a percentage of the distribution made by Holdings when such distributions exceed specified internal rate of return thresholds. Those thresholds had not been met as of December 31, 2011.
Option Exercises and Stock Vested Table
The table below shows the number of shares of our common stock acquired by our named executive officers during 2011 upon the vesting of Plan awards.
Option Exercises and Stock Vested
as of Fiscal Year-End December 31, 2011
(1) The participant’s profits interests under the Plan represent the right to receive a percentage of the distribution made by Holdings when such distributions exceed specified internal rate of return thresholds. Those thresholds had not been met as of December 31, 2011.
Pension Benefits
We do not maintain any defined benefit pension plans.
Nonqualified Deferred Compensation
We do not maintain any nonqualified deferred compensation plans.
Employment Arrangements
We have entered into employment agreements with certain of our named executive officers.
Our agreement with Mr. Ivey became effective January 1, 2009 and had a term of eleven months, with automatic renewal for additional one year periods unless either we or Mr. Ivey elects not to renew. He currently receives an annual base salary of $300,000 and is entitled to an annual bonus of up to 150% of his base salary as may be determined from time to time in the sole discretion of the board of directors based on the achievement of certain performance criteria. The board of directors also evaluates Mr. Ivey’s salary on an annual basis and will determine if any additional increases are warranted. The employment agreement prohibits Mr. Ivey from competing with us during his employment and for a period of one year thereafter if he is terminated for cause or he resigns without good reason. Mr. Ivey is also subject to a non-solicitation agreement for two years after his termination for any reason (other than in connection with a change of control event) and a confidentiality obligation after cessation of his employment with us. Payments under the agreement to Mr. Ivey in connection with his termination or a change of control are described below under “- Potential Payments Upon Termination or Change of Control.”
Our agreement with Mr. Mabie became effective February 8, 2010 and had a term of one year. This agreement was extended through February 8, 2012. We and the board of directors are currently in discussion with Mr. Mabie to extend the term of this agreement. He currently receives an annual base salary of $250,000 and pursuant to the agreement is entitled to an annual bonus as may be determined from time to time in the sole discretion of the board of directors based on the achievement of certain performance criteria. Pursuant to the agreement, the board of directors also evaluates Mr. Mabie’s salary on an annual basis and will determine if any additional increases are warranted. Pursuant to the agreement, Mr. Mabie is also subject to a non-solicitation agreement for six months after his termination for any reason (other than in connection with a change of control event) and a confidentiality obligation after cessation of his employment with us. Pursuant to the agreement, payments under the agreement to Mr. Mabie in connection with his termination or a change of control are described below under “- Potential Payments Upon Termination or Change of Control.”
Our agreements with Messrs. Munsell and Langford became effective November 30, 2007 and have a term of one year, with automatic renewal for additional one year periods unless either we or Mr. Munsell or Mr. Langford, as applicable, elects not to renew. They each currently receive an annual base salary of $240,000 and each is entitled to an annual bonus of up to 100% of his base salary as may be determined from time to time in the sole discretion of the board of directors based on the achievement of certain performance criteria. The board of directors also evaluates their salaries on an annual basis and will determine if any additional increases are warranted. The employment agreements prohibit Messrs. Munsell and Langford from competing with us during his employment and for a period of one year thereafter if he is terminated for cause or he resigns without good reason. Messrs. Munsell and Langford are also subject to a non-solicitation agreement for two years after his termination for any reason (other than in connection with a change of control event) and a confidentiality obligation after cessation of his employment with us. Payments under the agreements to Messrs. Munsell and Langford in connection with his termination or a change of control are described below under “- Potential Payments Upon Termination or Change of Control.”
Our agreement with Mr. LaRocque became effective January 1, 2011 and had a term of eleven months, with automatic renewal for additional one year periods unless either we or Mr. LaRocque elects not to renew. He currently receives an annual base salary of $185,000 and is entitled to an annual bonus of up to 70% of his base salary as may be determined from time to time in the sole discretion of the board of directors based on the achievement of certain performance criteria. The board of directors also evaluates Mr. LaRocque’s salary on an annual basis and will determine if any additional increases are warranted. The employment agreement prohibits Mr. LaRocque from competing with us during his employment and for a period of one year thereafter if he is terminated for cause or he resigns without good reason. Mr. LaRocque is also subject to a non-solicitation agreement for two years after his termination for any reason (other than in connection with a change of control event) and a confidentiality obligation after cessation of his employment with us. Payments under the agreement to Mr. LaRocque in connection with his termination or a change of control are described below under “- Potential Payments Upon Termination or Change of Control.”
Potential Payments upon Termination and Change of Control
The following tables describe the potential payments upon termination or a change in control for our named executive officers.
Name: James G. Ivey
Title: Chief Financial Officer
Name: Robert D. LaRocque
Title: Vice President of Finance and Treasurer
Name: Gary Mabie
Title: Chief Operating Officer
Name: Marshall L. Munsell
Title: Senior Vice President of Business Development
Name: Thomas C. Langford
Title: Senior Vice President and General Counsel
(1) For purposes of this analysis, we assumed that the effective date of termination is December 31, 2011, and that the executive’s compensation is as follows: Mr. Ivey’s base salary is equal to $300,000 and annual incentive target opportunity is equal to 150% of base salary; Mr. LaRocque’s base salary is equal to $185,000 and annual incentive target opportunity is equal to 70% of base salary; Mr. Mabie’s base salary is equal to $250,000 and annual incentive target opportunity is equal to 100% of base salary; Mr. Langford’s base salary is equal to $240,000 and annual incentive target opportunity is equal to 100% of base salary; and Mr. Munsell’s base salary is equal to $240,000 and annual incentive target opportunity is equal to 100% of base salary. We have assumed for purposes of this table that all bonus targets established by our board of directors have been met and our board of directors approved the payment of a bonus to the amount reflected. We have not reflected any payment for unused vacation accrued during the year.
(2) Payments in connection with a change of control event (as defined in the employment agreements for each named executive officer) are payable if (i) they are terminated by us without cause (as defined in the employment agreements) or they terminate for good reason (as defined in the employment agreements) within 24 months after the change of control event or (ii) they terminate their employment for any reason within 30 days of the six month anniversary of the change of control event.
(3) Under “Involuntary Not for Cause Termination or Voluntary Termination for Good Reason,” severance is calculated as 1x base salary and is payable in accordance with standard payroll practices. Under “After a Change in Control,” severance is calculated as 2x base salary and is payable in accordance with standard payroll practices.
(4) Under “Involuntary Not for Cause Termination or Voluntary Termination for Good Reason” and “After a Change in Control,” bonus is calculated assuming all performance criteria have been met.
(5) All unvested Plan awards are automatically forfeited for no consideration in connection with a termination of the employee for any reason. In addition, all Plan awards become fully vested in connection with a change of control. The participant’s profits interests under the Plan represent the right to receive a percentage of the distribution made by Holdings when such distributions exceed specified internal rate of return thresholds. Those thresholds had not been met as of December 31, 2011
(6) Health and Welfare Benefits Continuation is calculated as 18 months of COBRA expense under “Involuntary Not for Cause Termination or Voluntary Termination for Good Reason” and “After a Change in Control.” In both categories, the benefits payable will be reduced to the extent that the named executive officer becomes eligible to comparable benefits from a new employer or other entity. Welfare Benefits include various life, accident and disability insurance policies. For the purposes of this analysis, the maximum payout was calculated by assuming accidental death. Benefits will be paid in accord with each policy’s schedule of insurance and terms of the covered losses including the age of the participant.
(7) Our agreement with Mr. Mabie became effective February 8, 2010 and had a term of one year. This agreement was extended through February 8, 2012. We and the board of directors are currently in discussion with Mr. Mabie to extend the term of this agreement.
Compensation Committee Interlocks and Insider Participation
All compensation decisions are made by our board of directors. Other than Mr. Ivey, none of the members of our board of directors is or has been an officer or employee of our company or had any related person transactions involving us. Other than Mr. Ivey, none of our executive officers currently serves, or in the past year has served, as a member of the board of directors or compensation committee (or other committee serving an equivalent function) of any entity that has one or more executive officers serving on our board of directors or compensation committee.
Director Compensation
Other than Mr. Ivey, none of the members of our board of directors received any compensation from us during 2011. Certain of our equity sponsors (for which certain of our directors serve as representatives on our board of directors) may under certain conditions receive fees pursuant to the Monitoring Agreement described below under “Certain Relationships and Related Party Transactions.”
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Security Ownership of Certain Beneficial Owners and Management
The following table sets forth information with respect to the beneficial ownership of our common stock and our Series A preferred stock as of March 29, 2012.
(1) Our parent company, Holdings, is a holding company and the holder of record of 100% of our issued and outstanding common stock. The number of shares of our common stock shown as beneficially owned is based on the respective beneficial ownership interest of each investor in Holdings and assumes the Class C membership interests in Holdings are not currently entitled to distributions. Holdings has three classes of membership interests outstanding: Class A, substantially all of which is owned by affiliates of ACON Funds Management, Guggenheim Investment Management and West Coast Partners; Class B, which is held by the original investors from 2005; and Class C, which are non-voting profit interests issued to our management team. All voting and investment decisions with respect to our common stock are made by the board of directors of Holdings, which is made up of representatives of ACON, Guggenheim and West Coast, as well as our chief executive officer.
(2) The holders of our Series A preferred stock are party to the Stockholders’ Agreement, which will remain in effect for so long as we remain a subsidiary of Holdings. The Stockholders’ Agreement provides our Series A preferred stockholders with the right to, among other things, appoint four of the five members of our board of directors. The Stockholders’ Agreement also places restrictions on the ability of the holders of our Series A preferred stock to transfer their shares and requires that certain actions be approved unanimously or by a supermajority of our board of directors.
(3) Based on 2,700,000 shares of our Series A preferred stock outstanding as of March 29, 2012.
(4) Includes shares held by ACON Milagro Second Lien Investors, LLC. Jonathan Ginns and Mo Bawa exercise voting and investment authority over these shares and serve as the representatives of ACON on our board of directors. See “Management - Board of Directors.”
(5) Includes shares held by 1888 Fund, Ltd., Copper River CLO Ltd., Green Lane CLO Ltd., NZC Guggenheim Master Fund Limited, Sands Point Funding Ltd., Guggenheim Energy Opportunities Fund, LP, Kennecott Funding Ltd., IN-FP1, LLC and New Energy LLC. Guggenheim Investment Management, LLC is a wholly-owned subsidiary of Guggenheim Capital, LLC, which exercises voting and investment authority over these shares. Thomas J. Hauser serves as the representative of Guggenheim on our board of directors. See “Item 10. Directors, Executive Officers and Corporate Governance - Board of Directors.”
(6) Includes shares held by Touradji Diversified Holdings, LLC, Touradji Diversified Ventures I Inc., Touradji Global Resources Holdings, LLC, and Touradji Global Resources Ventures I Inc., each of which is managed by Touradji Capital Management, LP. Mr. Paul Touradji is the General Partner of Touradji Capital Management and has voting and investment authority over the shares.
(7) Adam Cohn exercises voting and investment authority over these shares and serves as the representative of West Coast Energy Partners on our board of directors. See “Item 10. Directors, Executive Officers and Corporate Governance - Board of Directors.”
(8) Mr. Brad Mardhall exercises voting and investment authority over these shares.
(9) Includes shares held by AIG Vantage Capital, L.P. and AIG PEP IV Co-Investment, L.P. Jonathan Sterns exercises voting and investment authority over these shares.
(10) Includes investors who individually beneficially own less than 1% of our outstanding common stock. Members of our management team do not beneficially own any shares of our capital stock other than Class C membership interests in Holdings. See “Item 11. Executive Compensation.”
Securities Authorized for Issuance Under Equity Compensation Plans
We have no outstanding equity compensation plans under which our securities are authorized for issuance. Equity compensation plans are maintained by Holdings, our parent company.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Certain Relationships and Related Party Transactions
In the ordinary course of our business and in connection with our financing activities, we have entered into transactions with certain of our affiliates and significant stockholders. All of the transactions set forth below were approved by the unanimous vote of our board of directors. We believe that we have executed all of the transactions set forth below on terms no less favorable to us than could have been obtained from unaffiliated third parties.
Monitoring Agreement
In connection with the acquisition of Petrohawk Energy Corporation’s Gulf Coast assets in November 2007, Holdings entered into a Monitoring Agreement with our equity sponsors ACON, Guggenheim and West Coast (the “Monitoring Agreement”). Pursuant to the terms of the Monitoring Agreement, the equity sponsors agreed to provide Holdings with management and advisory services during the term of the Monitoring Agreement, including, but not limited to, services relating to: (a) financing matters; (b) acquisitions, dispositions and corporate change of control transactions, (c) commodity risk management, (d) day-to-day operational matters and (e) such other services as agreed to in writing. On the date Holdings entered into the Monitoring Agreement, the equity sponsors were paid a one-time equity commitment fee of $8.3 million. In addition, during the term of the Monitoring Agreement, and in exchange for services provided under the Monitoring Agreement, we are required to pay our equity sponsors an annual fee of $2.5 million payable in four quarterly installments. Although we are not a party to the Monitoring Agreement and therefore have no liability for payment of the fees thereunder, because Holdings is a holding company with no operations or assets other than our outstanding common stock, Holdings is dependent on distributions from us to fund its payment obligations under the Monitoring Agreement. In addition, because 100% of our common stock is held by Holdings, Holdings has the ability to require us to make distributions. However, as a result of restrictions under our prior first lien credit agreement and our existing first lien credit agreement, to date we have not been permitted to make distributions to Holdings sufficient to pay the monitoring fee and as a result the monitoring fee has continued to accrue. As of December 31, 2011, this accrued obligation was an aggregate of $8.1 million. We expect similar restrictions on distributions to make these payments will continue in the indenture governing these notes and the 2011 Credit Facility. The Monitoring Agreement will continue in effect until all of the equity sponsors consent to its termination. As part of the Monitoring Agreement, Holdings agreed to indemnify the equity sponsors for claims resulting from services provided thereunder; provided such claims do not arise out of an equity sponsor’s gross negligence or willful misconduct. Further, the Monitoring Agreement does not limit the equity sponsors’ ability to provide similar services to other companies, including competitors, and does not require the equity sponsors to present Holdings with any corporate opportunity before informing a third party of such opportunity.
Development Services Agreement
Two of our wholly-owned subsidiaries, Milagro Producing, LLC (“Producing”) and Milagro Exploration, LLC (“Exploration”), are parties to a Development Services Agreement (the “Development Services Agreement”). Pursuant to the Development Services Agreement, Exploration provides Producing with oil and gas services relating to Producing’s owned and acquired properties. These services include: (a) geological and geophysical services, (b) project marketing services, (c) drilling, completion and operating services (including acting as an operator for oil and gas properties), (d) accounting services, (e) revenue distribution and joint interest billing services, (f) governmental compliance and regulatory filings support, (g) general business services, (h) land services, (i) production handling, marketing and hedging, and (j) such additional services as the parties mutually agree. In return for services provided under the Development Services Agreement, Exploration receives reimbursement for costs incurred and the right to hold title to or be the licensee of all geological and geophysical data procured during the course of its work performed under the Development Services Agreement. In addition, Producing provides the funds required for Exploration to develop and acquire one or more proprietary seismic programs with all data derived from such a program being the property of Exploration. Upon termination of the Development Services Agreement, and in some cases before then, Exploration will reimburse Producing for the costs associated with acquiring the proprietary seismic program. The Development Services Agreement will remain in effect as long as Producing remains in existence and may be terminated at any time for any reason by Producing.
Director Independence
Our board of directors is composed of five members, each of whom is elected annually by our stockholders. Under the Stockholders’ Agreement, which is effective for so long as we are a subsidiary of Holdings, holders of our Series A preferred stock have the right to appoint four of the five members of our board of directors. The fifth director is our chief executive officer. As a result, none of our directors are considered independent at this time.
Item 14.
Item 14. Principal Accounting Fees and Services
Deloitte has served as our independent auditors for each of the past two fiscal years.
The following table presents aggregate fees for professional services rendered by our independent registered public accounting firm, Deloitte for the audit of our annual consolidated financial statements for the years ended December 31, 2011 and 2010.
(1) Audit fees are comprised of annual audit fees and quarterly review fees.
(2) Audit-related fees for fiscal years 2011 and 2010 are comprised of fees related to accounting consultation fees and our registration statement on Form S-4.
Policy on Board Pre-Approval of Services of Independent Registered Public Accounting Firm
Our board of directors has responsibility for appointing, setting compensation and overseeing the work of the independent registered public accounting firm. In recognition of this responsibility, the board of directors has established a policy to pre-approve all audit and permissible non-audit services provided by the independent registered public accounting firm. Prior to engagement of the independent registered public accounting firm for the following year’s audit, management will submit to the board of directors for approval a description of services expected to be rendered during that year for each of following categories of services:
Audit services include audit work performed in the preparation and audit of the annual financial statements, review of quarterly financial statements, reading of annual, quarterly and current reports, as well as work that generally only the independent auditor can reasonably be expected to provide, such as the provision of consents and comfort letters in connection with the filing of registration statements.
Audit-related services are for assurance and related services that are traditionally performed by the independent auditor, including due diligence related to mergers and acquisitions and special procedures required to meet certain regulatory requirements.
Tax services consist principally of assistance with tax compliance and reporting, as well as certain tax planning consultations.
Other services are those associated with services not captured in the other categories. We generally do not request such services from our independent auditor.
Prior to the engagement, the board of directors pre-approves these services by category of service. The fees are budgeted, and the Board requires the independent registered public accounting firm and management to report actual fees versus the budget periodically throughout the year by category of service. During the year, circumstances may arise when it may become necessary to engage the independent registered public accounting firm for additional services not contemplated in the original pre-approval. In those instances, the board of directors requires specific pre-approval before engaging the independent registered public accounting firm.
The board of directors may delegate pre-approval authority to one or more of its members. The member to whom such authority is delegated must report, for informational purposes only, any pre-approval decisions to the audit board of directors at its next scheduled meeting.
The services described above for 2011 provided by Deloitte were approved by the board of directors pursuant to paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S-X. None of the services described above for 2010 provided by Deloitte were approved by the board of directors pursuant to paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules
1. Financial Statements. Reference is made to the Index to Consolidated Financial Statements at Item 8 of this annual report on Form 10-K.
2. Financial Statement Schedules. All schedules are omitted because they are not applicable or the required information is shown in the financial statements or the notes to the financial statements.
3. Exhibits.
Description of Exhibits
* Filed herewith.
+ Management contract or compensatory plan or arrangement.
GLOSSARY OF OIL & GAS TERMS
The following are abbreviations and definitions of certain terms commonly used in the oil and natural gas industry and in this prospectus. The definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a) of Regulation S-X.
3-D seismic. The method by which a three dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, development and production.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to oil or other liquid hydrocarbons.
BBbl. One billion Bbls.
Bcf. One billion cubic feet of natural gas.
Boe. One barrel equivalent of crude oil, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs.
Boe/d. Boe per day.
Completion. The installation of permanent equipment for the production of oil or natural gas. Completion of the well does not necessarily mean the well will be profitable.
Completion Rate. The number of wells on which production casing has been run for a completion attempt as a percentage of the number of wells drilled.
Development Well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry Well. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion of an oil or natural gas well.
Exploratory Well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir.
Fault. A break in the rocks along which there has been movement of one side relative to the other side.
Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which we have a working interest.
Lease Operating Expenses. The expenses, usually recurring, which pay for operating the wells and equipment on a producing lease.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
MBoe. One thousand barrels of oil equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs.
MBoe/d. MBoe per day.
Mcf. One thousand cubic feet of natural gas.
MMBbl. One million barrels of oil or other liquid hydrocarbons.
MMBoe. One million barrels of oil equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs.
MMBtu. One million Btu, or British Thermal Units. One British Thermal Unit is the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
MMcf. One million cubic feet of natural gas.
Net Acres or Net Wells. Gross acres or wells multiplied, in each case, by the percentage working interest we own.
Net Production. Production that we own less royalties and production due others.
Oil. Crude oil, condensate or other liquid hydrocarbons.
Operator. The individual or company responsible for the exploration, development and production of an oil or natural gas well or lease.
Pay. The vertical thickness of an oil and natural gas producing zone. Pay can be measured as either gross pay, including non-productive zones or net pay, including only zones that appear to be productive based upon logs and test data.
Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved Reserves. The estimated quantities of crude oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved Undeveloped Reserves. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
Royalty. An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
Standardized Measure. The after-tax present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.
Trend. A geographical area that has been known to contain certain types of combinations of reservoir rock, sealing rock and trap types containing commercial amounts of hydrocarbons.
Undeveloped Acreage. Acreage which is not allocated or assignable to producing wells or wells capable of production.
Working Interest. An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
MILAGRO OIL & GAS, INC.
Date: March 29, 2012
By:
/s/ James G. Ivey
Name: James G. Ivey
Title: President and Chief Executive Officer (Principal executive officer) and Director
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.
Supplemental Information to Be Furnished With Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act
The registrant has not sent, and does not expect to send, an annual report or proxy statement to its security holders.