Item 1A. Risk Factors
This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, including statements about our plans, strategies, expectations, assumptions and prospects. Forward-looking statements are all statements other than statements of historical facts, such as those statements regarding potential oil and gas discoveries, oil and gas exploration, development and production activities and costs, capital expenditures, reclamation, indemnification and environmental obligations and costs, potential quarterly and annual production and flow rates, reserve estimates, and projected operating cash flows and liquidity, among others. The words “anticipates,” “may,” “can,” “plans,” “believes,” “estimates,” “expects,” “projects,” “intends,” “likely,” “will,” “should,” “to be,” and any similar expressions and/or statements that are not historical facts are intended to identify those assertions as forward-looking statements.
We caution readers that forward-looking statements are not guarantees of future performance or exploration and development success, and our actual exploration experience and future financial results may differ materially from those anticipated, projected or assumed in the forward-looking statements. Important factors that may cause our actual results to differ materially from those anticipated by the forward-looking statements include, but are not limited to, those associated with general economic and business conditions, failure to realize expected value creation from acquired properties, variations in the market demand for, and prices of, oil and natural gas, drilling results, unanticipated fluctuations in flow rates of producing wells due to mechanical or operational issues (including those experienced at wells operated by third parties where we are a participant), changes in oil and natural gas reserve expectations,
the potential adoption of new governmental regulations, unanticipated hazards for which we have limited or no insurance coverage, failure of third party partners to fulfill their capital and other commitments, the ability to satisfy future cash obligations and environmental costs, adverse conditions, such as high temperatures and pressure that could lead to mechanical failures or increased costs, the ability to retain current or future lease acreage rights, the ability to obtain regulatory approvals and significant project financing for the potential MPEHtm project, the failure to consummate the FCX/MMR merger, access to capital to fund drilling activities, as well as other general exploration and development risks and hazards, and other factors.
Investors are cautioned that many of the assumptions upon which our forward-looking statements are based are likely to change after our forward-looking statements are made, including for example the market prices of oil and natural gas, which we cannot control, and production volumes and costs, some aspects of which we may or may not be able to control. Further, we may make changes to our business plans that could or will affect our results. We caution investors that we do not intend to update our forward-looking statements more frequently than quarterly, notwithstanding any changes in our assumptions, changes in our business plans, our actual experience, or other changes, and we undertake no obligation to update any forward-looking statements.
Important factors that could cause actual results to differ materially from our expectations include, without limitation, the following:
Risks Relating to Financial Matters
We need significant amounts of cash to service our debt. If we are unable to generate sufficient cash to service our debt, our financial condition and results of operations could be negatively affected.
As of December 31, 2012 our outstanding debt totaled $557.3 million, including $67.8 million of our 5¼% Senior Notes due October 6, 2013, $300 million of our 11.875% Senior Notes due November 15, 2014 and $189.5 million of our 4% senior notes due December 30, 2017 as further described in Note 7. We must generate sufficient amounts of cash to service and repay our debt and to conduct our planned exploration and development activities. Our ability to generate cash will be affected by general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. Future borrowings may not be available to us under our amended and restated credit facility or from the capital markets in amounts sufficient to pay our obligations as they mature or to fund other liquidity needs. In addition, disruptions in the credit and financial markets, such as those that occurred in late 2008, can constrain our access to capital and increase its cost. The inability to service, repay or refinance our indebtedness would have a negative impact on our financial condition and results of operations.
Agreements governing our indebtedness restrict our ability to incur additional debt and contain covenants and other restrictions that may limit our ability to respond to opportunities as they arise or execute our capital spending and related initiatives.
The terms of our amended and restated credit facility and other financing agreements governing our indebtedness restrict our ability to incur additional debt. Additionally, because the availability under our credit facility is subject to a borrowing base determined by the estimated future cash flows from our oil and natural gas reserves, a decline in the pricing for these commodities may result in a reduction in our borrowing base, which reduction could be significant, and as a result, would reduce the capital available to us.
If future debt financing is not available to us when required (as a result of limited access to the credit markets or otherwise), or is not available on acceptable terms, we may be unable to invest needed capital for our drilling and exploration activities, take advantage of business opportunities, respond to competitive pressures or refinance maturing debt, or be forced to sell some of our assets on an untimely basis or under unfavorable terms, any of which could have a material adverse effect on our financial condition and results of operations.
Our credit facility contains covenants and other restrictions customary for oil and gas borrowing base credit facilities, including limitations on debt, liens, dividends, voluntary redemptions of debt, investments, asset sales and transactions with affiliates. In addition, our credit facility requires that we
maintain certain financial tests, including a leverage test (Total Debt to EBITDAX, as those terms are defined in the facility, for the preceding four quarters) and a current ratio test (current assets to current liabilities, subject to certain adjustments as of the end of the quarter). During periods in which crude oil and natural gas prices or other conditions reflect the adverse impact of cyclical market trends or other factors, we may not be able to comply with the applicable financial covenants, which could have a material adverse effect on our financial condition.
Volatile oil and gas prices could adversely affect our financial condition and results of operations.
Our success is largely dependent on oil and natural gas prices, which are extremely volatile. Any substantial or extended decline in the price of oil and gas will have a negative impact on our business operations and future revenues. Moreover, oil and gas prices depend on factors we cannot control, such as:
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supply and demand for oil and gas and expectations regarding supply and demand;
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weather;
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actions by OPEC and other major producing companies;
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political conditions in other oil-producing and gas-producing countries, including the possibility of insurgency, terrorism or war in such areas;
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the prices of foreign imports and the demand for and availability of alternate fuel sources;
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technological advances affecting energy exploration, production and consumption;
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general economic conditions in the United States and worldwide, including the value of the U.S. dollar relative to other major currencies; and
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governmental regulations.
With respect to our business, prices of oil and gas will affect:
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our revenues, cash flows, profitability and earnings;
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our ability to attract capital to finance our operations and the cost of such capital;
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the amount that we are allowed to borrow under our credit facility; and
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the value of our oil and gas properties and our oil and gas reserve volumes.
If crude oil and natural gas prices decline or our exploration efforts are unsuccessful, we may be required to write down the capitalized costs of individual oil and natural gas properties.
From time to time, declines in the market price for oil and natural gas coupled with certain other operational factors trigger impairment assessments that may ultimately result in impairment charges to reduce the carrying values of our properties. Additional write-downs of the capitalized costs of individual oil and natural gas properties may occur if information comes to our attention to warrant a downward adjustment to our estimated proved oil and gas reserves, to increase our estimates of development costs or to conclude that the results of exploratory drilling will be unproductive. A write-down could adversely affect our results of operations and financial condition and the trading prices of our securities.
We use the successful efforts accounting method which requires all property acquisition costs and costs of exploratory and development wells to be capitalized when incurred, pending the determination of whether proved reserves are discovered. Additionally, we assess our properties for impairment periodically, based on future estimates of the value of proved and risk-adjusted probable reserves, oil and natural gas prices, production rates and operating, development and reclamation costs based on operating budget forecasts.
If the capitalized costs of our oil and natural gas properties, on a field-by-field basis exceed the estimated future net cash flows of that field, we record impairment charges to reduce the capitalized costs of each such field to our revised estimate of the field’s fair market value. We also record charges if proved reserves are not discovered at exploratory wells. Any impairment charges that we take will reduce our earnings and potentially our stockholders’ equity. Once incurred, an impairment charge cannot be reversed at a later date even if we experience subsequent increases in the price of oil or natural gas, or both, or increases in the amount of our estimated proved reserves.
Increasing domestic production and availability of unconventional sources of gas, including gas extracted from shale formations and LNG, may reduce the price of natural gas, and could have an adverse effect on our financial condition and results of operations.
Recently, there has been an increase in the worldwide supply of unconventional gas, including gas extracted from shale formations utilizing advances in techniques for horizontal drilling and the fracturing of rock formations and LNG. While until recently production of gas from unconventional sources was a relatively small portion of current North American gas production, it has been increasing and is expected to continue to increase in the future. The global financial crisis also significantly impacted financial and commodity markets and has contributed to extreme volatility in oil and natural gas markets since that time, especially for natural gas prices. The amount of natural gas in storage increased as a result of this decreased demand, which contributed to the current oversupply of natural gas. Many economic forecasts predict an oversupplied natural gas market over the near-to-intermediate term, the effect of which, absent other factors, could result in a low natural gas price environment for the next several years and possibly beyond.
As described more fully in Items 7. and 7A. “Management’s Discussion and Analysis of Financial Condition and Results of Operation and Quantitative and Qualitative Disclosures About Market Risk,” our production volume for 2012 is comprised of approximately 63 percent natural gas and our revenues are generally more sensitive to changes in the market price of natural gas than to changes in the market price of oil. As a result, any significant or prolonged increase in the domestic or worldwide supply of unconventional gas may result in a reduction in the volume and price of the natural gas we produce, which would likely have an adverse effect on our financial condition and results of operations.
Our ability to collect our accounts receivable depends on the continuing creditworthiness of our customers.
The majority of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. Our credit risk associated with these third parties may increase as we produce and sell oil and natural gas on a larger scale. Additionally, economic conditions and the price of oil and natural gas may, among other things, impair our ability to timely collect our receivables from these parties, result in downgrades to the credit ratings of our customers or other third parties that do business with us, or have other adverse consequences. While we sell oil and natural gas to third parties that we believe are reasonable credit risks, there is no guarantee, especially in light of these factors, that the risk associated with the creditworthiness of these parties will not increase.
Our future revenues will be reduced as a result of agreements that we have entered into and may enter into in the future with third parties. Any failure of our partners to fulfill their obligations and commitments to us could have an adverse effect on our financial condition and results of operations.
We currently have agreements with third parties to support the funding of the exploration and development of certain of our properties and we may seek to enter into additional farm-out or similar arrangements with other third parties in the future.
Our ownership interest in prospects subject to farm-out or other exploration arrangements revert to us only upon the achievement of a specified production threshold or the receipt by our partners and co-ventures of specified net production proceeds. Consequently, even if exploration and development of our prospects is successful, we cannot give assurance that such exploration and development will result in an increase in our revenues or our proved oil and gas reserves or when such increases might occur.
Additionally, our ability to enter into future beneficial relationships with third parties for our exploration and production activities may be limited, and as a result, may have an adverse effect on our current operational strategy and related business initiatives. Our farm-out partners and working interest co-owners may also be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farm-out partner, we would either have to find a new farm-out partner or obtain alternative funding in order to complete the exploration and development of the prospects subject to the farm-out agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. The degree to which these and other factors may adversely impact our partners and third-party operators (and the extent of any associated effect on us) is uncertain.
We enter into contractual commitments with third parties related to our planned oil and gas exploration and development activities, including costs related to projects currently in progress, inventory purchase commitments and other exploration expenditures, some of which may be substantial. Additionally, a portion of our exploration program involves the sharing of certain costs associated with these expenditures with our partners.
At December 31, 2012, we had $118.9 million of contractual commitments related to our planned oil and gas exploration and development activities, including $16.0 million of expenditures for drilling rig contract charges, a portion of which we expect to share with our partners in our exploration program. A failure of our partners to fulfill their obligations or commitments to us, would have an adverse effect on our operating results and financial condition.
We have incurred losses from our operations in the past and may continue to do so in the future. Our failure to achieve profitability in the future could adversely affect the trading price of our securities and our ability to raise additional capital.
Our losses from continuing operations were $97.0 million in 2012, $6.6 million in 2011 and $117.0 million in 2010. No assurance can be given that we will achieve profitability or positive cash flows from our operations in the future. Our failure to achieve profitability in the future could adversely affect the trading price of our securities and our ability to raise additional capital. In addition, while there are signs that the global economy has improved, the potential remains for further volatility and disruption in the capital and credit markets. During the recent global recession, the markets produced downward pressure on stock prices and credit capacity for certain issuers without regard to those issuers’ underlying financial strength. If these levels of market disruption and volatility return, our business, financial condition and results of operations, as well as our ability to access capital, may all be negatively impacted.
We are responsible for reclamation, environmental indemnification and other obligations associated with our oil and gas properties and our former sulphur operations.
As of December 31, 2012, we had accrued $245.6 million relating to reclamation liabilities with respect to our oil and gas properties. Among these reclamation obligations are the plugging and abandonment of wells, the reclamation and removal of platforms, facilities and pipelines and the repair and replacement of wells, equipment and facilities. The scope and cost of these obligations may ultimately be materially greater than currently estimated.
As of December 31, 2012, we had $14.8 million relating to accrued reclamation liabilities with respect to our discontinued sulphur operations at Main Pass and $2.6 million relating to accrued reclamation liabilities with respect to our other discontinued sulphur operations.
We cannot give assurance that actual reclamation costs ultimately incurred will not exceed our current and future accruals for reclamation costs, that we will have the necessary resources to satisfy these obligations in the future, or that we will be able to satisfy applicable bonding requirements.
In addition, we are responsible for indemnification obligations related to the former sulphur operations previously engaged in by us and our predecessor companies. We have also assumed, and agreed to indemnify IMC Global Inc. (now a subsidiary of Mosaic Company) from certain potential obligations, including environmental obligations relating to historical oil and gas operations conducted by the Freeport-McMoRan companies prior to the 1997 merger of Freeport-McMoRan Inc. and IMC Global. We have also assumed and agreed to indemnify Newfield Exploration Company (Newfield) from certain potential obligations, including environmental obligations relating to a 2007 oil and gas property
acquisition. The scope and cost of these obligations may ultimately be materially greater than estimated at the time such indemnifications were granted and the related obligations were assumed. Our liabilities with respect to those obligations could adversely affect our operations and liquidity.
Risks Relating to our Operations
Our exploration and development activities may not be commercially successful.
Oil and natural gas exploration and development activities involve a high degree of risk that hydrocarbons will not be found, that they will not be found in commercial quantities, or that the value produced will be less than the related drilling, completion and operating costs. The 3-D seismic data and other technologies that we use provide no assurance prior to drilling a well that oil or natural gas is present or economically producible. The cost of drilling, completing and operating a well is often uncertain, especially when drilling offshore and when drilling deep and ultra-deep wells. Our drilling operations may be changed, delayed or canceled as a result of numerous factors that we cannot control, including:
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continued economic uncertainty in the global financial and credit markets;
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the market price of oil and natural gas;
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unexpected drilling conditions;
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unexpected pressure or irregularities in geologic formations;
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equipment failures or accidents;
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title imperfections;
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tropical storms, hurricanes and other adverse weather conditions, which are common in the Gulf of Mexico during certain times of the year;
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regulatory requirements; and
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equipment and labor shortages resulting in cost overruns.
Additionally, completion of a well does not guarantee that it will be profitable or even that it will result in recovery of the related drilling, completion and operating costs.
We anticipate that any of our near-term exploration and development activities will take place on deep and ultra-deep shelf prospects in the shallow waters of the Gulf of Mexico, an area that has had limited historical drilling activity due, in part, to its geologic complexity. Deeper targets are more difficult to detect with traditional seismic processing and the expense of drilling deep shelf wells and the risk of mechanical failure is significantly higher because of the higher temperatures and pressures found at greater depths. Our exploratory wells require significant capital expenditures, the costs of which could exceed $100 million per well, net to our interests, depending upon drilling and other operational challenges encountered in our ultra-deep drilling program before we can ascertain whether they contain commercially recoverable oil and natural gas reserves. There is no assurance that we will have, or be able to obtain, sufficient capital to pursue these expenditures or that our oil and natural gas exploration activities, either on the deep or ultra-deep shelf or elsewhere, will be commercially successful.
Our ultra-deep prospects target ultra-deep formations in the shallow water of the Gulf of Mexico and onshore Gulf Coast, which have greater risks and costs associated with their exploration and development than conventional Gulf of Mexico prospects. Our Davy Jones ultra-deep prospect has not yet been fully evaluated, and the ultimate impact of this potentially significant discovery will depend on, among other things, the volume of recoverable resources from the Davy Jones location and our ability to fund its commercial development through internally generated cash or third party funding.
Our objectives in our ultra-deep prospects target formations below the salt weld (i.e. ultra-deep targets) in the shallow water of the Gulf of Mexico and onshore in South Louisiana. These ultra-deep targets have not traditionally been the subject of exploratory activity in these regions, thus little direct comparative data is available. To date, there has been no production of hydrocarbons from ultra-deep reservoirs in these areas. As a result of the unavailability of direct comparative data and limitations of diagnostic tools that operate in the extreme temperatures and pressures encountered, it is much more difficult to predict with accuracy the reservoir quality and performance of ultra-deep formations. Additionally, ultra-deep formations are significantly more expensive to drill and complete than their conventional shallow water counterparts. Major contributors to such increased costs include (1) far higher temperatures and pressures encountered down hole and (2) longer drilling times. Thus, costs for drilling and completing ultra-deep wells are significantly higher than shelf equivalents at more conventional depths.
For example, our Davy Jones ultra-deep prospect has not yet been fully evaluated, and the ultimate impact of this potentially significant discovery will depend on, among other things, the volume of recoverable resources from the Davy Jones location, which will require significant capital expenditures for commercial development. In January 2010, we announced a potentially significant discovery at our Davy Jones ultra-deep prospect. However, flow testing is required to confirm the ultimate hydrocarbon flow rates from the separate zones within this prospect. Because of the pressures and temperatures encountered down hole, certain specialty completion equipment was required. Completion activities were initiated in the fourth quarter of 2011, and initial flow testing procedures were attempted in March 2012; however, we encountered mechanical issues with the originally designed perforating equipment. Operations to obtain a measurable flow test at the Davy Jones ultra-deep prospect were temporarily halted in January 2013 while we develop plans to pump a large scale hydraulic fracture treatment including proppant to facilitate hydrocarbon movement into the wellbore. Future plans will incorporate data gained to date at Davy Jones as well as potential core and log data from the in progress well at Lineham Creek, located onshore approximately 50 miles northwest of Davy Jones. The rig has been moved off location for several months while the hydraulic fracture treatment is designed. There is no assurance that we will be able to effectively complete the flow testing of this prospect, or that once completed, the potential of the discovery in terms of recoverable product will be confirmed. Our total investment in Davy Jones, which includes $474.8 million in allocated property acquisition costs, totaled $1,024.0 million at December 31, 2012. The continuing commercial development and exploitation of the Davy Jones prospect will also require significant additional capital expenditures.
We will require additional capital to fund our future drilling activities and the development of other projects. If we fail to obtain additional capital, we may not be able to continue our operations or the development of these projects.
Historically, we have funded our operations and capital expenditures through:
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cash flow from our operations;
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entering into exploration arrangements with third parties;
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selling oil and gas properties;
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borrowing money from banks;
• issuing senior notes; and
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selling preferred stock, common stock and securities convertible into common stock.
We incurred $505.1 million in capital expenditures in 2012. Drilling results, follow on development opportunities and general market factors, will determine our level of 2013 capital expenditures. Although we intend to fund our near-term expenditures with available cash, operating cash flows and borrowings under our senior secured revolving credit facility, we may need to raise additional capital through future equity or debt transactions to continue drilling activities and other project developments.
In the near term, we plan to continue to pursue the drilling of our exploration prospects, although we have and will continue to adjust our drilling plan and capital expenditures as necessary. However,
without adequate capital resources, our drilling and other activities may be limited and our business, financial condition and results of operations may be adversely affected.
The high-rate production and depletion characteristics of our Gulf of Mexico properties subject us to high reserve replacement needs. If we are unable to replace the reserves that we have produced, our reserves and revenues will decline.
Our future success depends in large part on our ability to find, develop and produce oil and natural gas reserves, and we cannot give assurance that we will be able to do so profitably. Unless we conduct successful exploration and development activities, acquire properties with proved reserves, or meet certain production and related thresholds with respect to our prospects subject to farm-out arrangements, our proved reserves will be depleted as they are produced.
Producing natural gas and oil reservoirs are generally characterized by declining production rates that vary depending on reservoir characteristics and other factors. Production from the Gulf of Mexico shelf generally declines at a faster rate than in other producing regions of the world. Reservoirs in the Gulf of Mexico shelf are generally sandstone reservoirs characterized by high porosity and high permeability that results in an accelerated recovery of production in a relatively short period of time, with a generally more rapid decline near the end of the life of the reservoir. This results in recovery of a relatively higher percentage of reserves during the initial years of production, and a corresponding need to replace these reserves with discoveries at new prospects within a relatively short time frame. There can be no assurance that we will be able to replenish our reserves at attractive prices or within a suitable timeframe.
The amount of oil and natural gas that we produce and the net cash flow that we receive from that production may differ materially from the amounts reflected in our reserve estimates.
Our estimates of proved oil and natural gas reserves are based on reserve engineering estimates using guidelines established by the SEC. Reserve engineering is a subjective process of estimating recoveries from underground accumulations of oil and natural gas that cannot be measured with complete accuracy. The accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions, such as:
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historical production from the area compared with production from other producing areas;
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assumptions concerning future oil and natural gas prices, future operating and development costs, workover, remediation and abandonment costs and severance and excise taxes;
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the effects that hedging contracts may have on our sales of oil and natural gas; and
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the assumed effects of government regulation and taxation.
These factors and assumptions are difficult to predict and may vary considerably from actual results. In addition, reserve engineers may make varying estimates of reserve quantities and cash flows based on different interpretations of the same available data. Also, estimates of proved reserves for wells with limited or no production history are less reliable than those based on actual production. Subsequent evaluation of the same reserves may result in variations in our estimated reserves, which may be substantial. As a result, all reserve estimates are imprecise.
Investors should not construe the estimated present values of future net cash flows from proved oil and natural gas reserves as the current market value of our estimated proved oil and natural gas reserves. As required by the SEC, we have estimated the discounted future net cash flows from proved reserves based on average prices, calculated as the twelve-month average of the first day of the month prices as adjusted for location and quality differentials, and costs prevailing at December 31, 2012. There are no adjustments to normalize those costs based on variations over time either before or after that year. Future prices and costs may be materially higher or lower. Future net cash flows also will be affected by such factors as:
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the actual amount and timing of production;
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changes in consumption by oil and gas purchasers; and
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changes in governmental regulations and taxation.
In addition, the 10 percent discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor to be used in determining fair values of proved oil and gas reserves. Changes in market interest rates at various times and the risks associated with our business or the oil and gas industry can vary significantly.
The accounting methods we use to record our exploration results may result in losses.
We use the successful efforts accounting method for our oil and natural gas exploration and development activities. This method requires us to expense geologic and geophysical costs and the costs of unsuccessful exploration wells as they are incurred, rather than capitalizing these costs up to a specified limit as permitted pursuant to the full cost accounting method. Because the timing difference between incurring exploration costs and realizing revenues from successful properties can be significant, losses may be reported even though exploration activities may be successful during a reporting period. Accordingly, depending on our exploration results, we may incur significant additional losses as we continue to pursue our exploration activities. We cannot give assurance that our oil and gas operations will enable us to achieve or sustain positive earnings or cash flows from operations in the future.
In the event we are unable to procure or maintain the suspension of operations (SOO) granted by the BSEE with respect to certain of our ultra-deep gas play acreage, our ability to fully realize value associated with such acreage could be adversely affected.
Our interests in the offshore leases located in federal waters on the Gulf of Mexico’s outer continental shelf are administered by the BOEM and BSEE and require compliance with BOEM and BSEE regulations and the OCSLA. Under the OCSLA, we are required to promptly and efficiently explore and develop any block or blocks to which these federal leases pertain within the initial term of such lease.
During the initial term of a lease, our ability to drill, rework, or produce a particular well in paying quantities may, despite our diligent efforts, be delayed. In this case, we have the ability to request that the BSEE extend the lease term beyond its scheduled expiration or termination. Provided our request in this regard is made timely and in accordance with regulatory guidelines, the BSEE may grant or direct an SOO on the condition that we commit to undertake or complete certain specified actions during the extended term. While the decision of the BSEE to grant or direct an SOO is made on a case-by-case basis, an SOO, if granted, is of limited duration.
At December 31, 2012, approximately 55,000 of the 381,000 gross acres associated with our ultra-deep gas play are scheduled to expire in 2013.
While it is not uncommon for companies in our industry to continue to operate leases under an SOO granted by the BSEE, in the event (1) we fail to satisfy any obligations or conditions set forth in an SOO with respect to a particular lease, (2) we are unable to procure an SOO from the BSEE prior to the expiration of a primary lease term, (3) the BSEE denies a request to grant an additional SOO (or an extension of an existing SOO) with respect to a particular lease, or (4) the BSEE terminates an SOO previously granted based on a determination that either the circumstances justifying the SOO no longer exist or that the lease otherwise now warrants termination, our ability to exploit some of the potentially valuable acreage associated with our ultra-deep gas play (including certain acreage contiguous to our Davy Jones and Blackbeard discoveries) could be adversely affected.
Compliance with environmental and other government regulations could be costly and could negatively affect production.
Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection, including without limitation, the Oil Pollution Act of 1990 (which imposes a variety of legal requirements on “responsible parties” related to the prevention of oil spills). These laws and regulations may:
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require the acquisition of a permit before drilling commences;
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restrict the types, quantities and concentration of various substances that can be released into the environment from drilling and production activities;
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limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;
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require remedial measures to address or mitigate pollution from former operations, such as plugging abandoned wells;
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require bonds or the assumption of other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment costs;
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impose substantial liabilities for pollution resulting from our operations; and
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require capital expenditures for pollution control equipment.
Additionally, new environmental laws or changes in existing laws (or their enforcement) may be enacted, and such new laws or changes may adversely affect the demand for our products or require significant additional expenditures by us to appropriately comply.
For example, recent scientific studies have suggested that emissions from the combustion of carbon-based fuels contribute to greenhouse effects and global climate change. In response to these findings, both federal and state governments have introduced or are contemplating regulatory changes regarding greenhouse gas emissions. The potential impacts of the passage of new climate change legislation or regulations to address, regulate or restrict the release of greenhouse gases are uncertain, and any such future laws could have an adverse effect on the general demand for the oil and natural gas that we produce or result in increased expenditures or additional operating expenditures.
Our operations could also result in liability for personal injury, property damage, oil spills, natural resource damages, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. Liability under environmental laws can be imposed retroactively and without regard to whether we knew of, or were responsible for, the presence of contamination on properties that we own or operate. Such liability may also be joint and several, meaning that the entire liability may be imposed on a party without regard to contribution. We could also be liable for environmental damages caused by previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred, which could have a material adverse effect on our results of operations and financial condition. We could also be held liable for any and all consequences arising out of human exposure to hazardous substances, including without limitation, asbestos-containing materials or other environmental damage which liability could be substantial.
The catastrophic explosion of the Deepwater Horizon in the Gulf of Mexico has resulted in increased governmental supervision of drilling, exploration and production activities in U.S. coastal waters, which could adversely affect our operations.
In April 2010, the Deepwater Horizon, an offshore drilling rig located in the deepwater of the Gulf of Mexico, sank following a catastrophic explosion and fire, which significantly and adversely disrupted oil & gas exploration activities in the Gulf of Mexico. The commission appointed by the President to study the causes of the catastrophe released its report and has recommended to the President certain legislative and regulatory measures that should be taken in order to minimize the possibility of a reoccurrence of a disastrous spill. In response to the Deepwater Horizon spill and the release of the commission report, the costs of conducting drilling and exploration activities in the Gulf of Mexico, particularly in deepwater, have increased.
Our operations are focused on the shelf of the Gulf of Mexico and Gulf Coast areas, where we maintain one of the largest acreage positions in the shallow waters of this region and have a significant number of ongoing exploration and development projects. In response to the catastrophe, the United States government imposed a suspension of all deepwater drilling and exploration activity in the Gulf of Mexico that expired on November 30, 2010. We do not operate in the deepwater of the Gulf of Mexico. However, although exploration activity in the shallow waters of the Gulf of Mexico has been allowed to re-commence, fewer new drilling permits have been issued to shallow water operators, and such permits are being issued at a slower pace since the catastrophe. Additionally, a series of Notice to Lessees (NTLs) issued by BOEM and BSEE impose new and more stringent requirements involved in the permitting process for new wells in the federal waters of the outer continental shelf. These NTLs increase the cost of operating in the Gulf of Mexico and lengthen the time required to obtain new drilling permits.
There are a number of uncertainties affecting the oil and gas industry that continue to exist in the aftermath of the Deepwater Horizon events and the release of the commission report, including the possible increase or elimination of the current $75 million cap for non-reclamation liabilities under the Oil Pollution Act of 1990, the uncertainty as to the continued availability and affordability of insurance for drilling and exploration activities, the uncertain overall legislative and regulatory response to the catastrophe, and the continuing difficulty and delay in obtaining drilling permits in the shallow water on a timely basis. Although the eventual outcome of these developments is currently unknown, additional regulatory and operational costs could have an adverse effect on our financial condition and results of operations.
The oil and gas industry is highly competitive and we face strong competition.
The business of oil and natural gas exploration, development and production is very competitive. Competition is particularly intense for prospective undeveloped acreage and purchases of proved oil and gas reserves. There is also competition for the rigs and related equipment and services that are necessary for us to develop and operate our oil and natural gas properties. Our competitive position is also highly dependent on our ability to recruit and retain geological, geophysical and engineering expertise. We are likely to continue to experience increased costs to attract and retain such professionals.
We compete for prospects, proved reserves, field services and qualified oil and gas professionals with major integrated oil and gas companies and numerous independent oil and gas companies, individual producers and operators. Many of our competitors have significantly greater financial and other resources than we have and may be better positioned to:
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access capital at a lower cost;
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adapt to fluctuations in the credit markets and periods of distressed or adverse economic conditions;
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adapt to an increasingly burdensome regulatory environment, particularly with respect to bearing increased compliance costs, in response to the Deepwater Horizon or other catastrophic events and uncertainties;
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define, evaluate, bid for and purchase properties and prospects;
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obtain equipment, supplies and labor on favorable terms;
•
develop, or buy, and implement new technologies; and
•
access more information relating to prospects.
We cannot control the activities related to properties in which we have an interest but do not operate.
Other companies operate several of the properties in which we have an interest. We do not control, and only have a very limited ability to influence, the operation of these properties or their associated costs. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors outside of our control, including:
•
timing and amount of capital expenditures;
•
the operator’s expertise, financial resources, and ability to sustain operations through periods of distressed or adverse economic conditions;
•
approval of operators or other participants in drilling wells; and
•
selection of technology.
Offshore operations are hazardous, and the hazards are not fully insurable at commercially reasonable costs.
Our operations are subject to the hazards and risks inherent in drilling for, producing and transporting oil and natural gas. These hazards and risks include:
•
fires;
•
natural disasters;
•
abnormal pressures in geologic formations;
•
blowouts;
•
cratering;
•
pipeline ruptures; and
•
spills.
If any of these or similar events occur, we could incur substantial losses as a result of death, personal injury, property damage, pollution, lost production, remediation and clean-up costs and other environmental or catastrophic damages.
We have historically maintained insurance for our operations, including liability, property damage, control of well, business interruption (when economically feasible), limited coverage for sudden and accidental environmental damages and other insurance. Due to increased claims made by insureds for losses experienced in recent years from hurricanes in the Gulf of Mexico, and disruption in the domestic and global financial markets, the windstorm component of property damage and control of well insurance coverage has become more limited in scope and amount and the cost of coverage has increased. The reduced windstorm component of our property damage and control of well insurance coverage may increase our risks of casualty loss which could have a material adverse effect on our results of operations and financial condition. Under our 2011 insurance program we had ceased carrying windstorm insurance coverage as the increased level of hurricane activity in the Gulf of Mexico in recent years increased premiums to levels that were not cost effective. However as part of our June 2012 renewal, we obtained partial coverage for losses resulting from named windstorms for a limited number of our properties. Any insurance that we purchase will not provide protection against all potential liabilities incident to the ordinary conduct of our business. Moreover, any insurance we maintain will be subject to coverage exclusions, limits, deductibles and other conditions. In addition, our insurance will not cover damages caused by war or environmental damages that occur over time. The occurrence of a material casualty loss that is not covered by insurance would adversely affect our results of operations and financial condition.
We are vulnerable to risks associated with operating in the Gulf of Mexico and onshore in the Gulf Coast area because we currently explore and produce exclusively in those areas.
Our strategy of concentrating our exploration and production activities on the Gulf of Mexico and onshore in the Gulf Coast area makes us more vulnerable to the risks associated with operating in those areas than our competitors with more geographically diverse operations. These risks include:
•
tropical storms and hurricanes, which are common in the Gulf of Mexico and the Gulf Coast area during the summer and early fall of each year;
•
extensive governmental regulation (including regulations that may, in certain circumstances, impose strict liability for pollution damage); and
•
interruption or termination of operations by governmental authorities based on environmental, safety or other considerations.
These exposures in the Gulf of Mexico and the Gulf Coast area could have a material adverse effect on our results of operations and financial condition.
Shortages of supplies, equipment and personnel may adversely affect our operations.
Our ability to conduct operations in a timely and cost effective manner depends on the availability of supplies, equipment and personnel. The offshore oil and gas industry is cyclical and experiences periodic shortages of drilling rigs, work boats, tubular goods, supplies and experienced personnel. Shortages can delay operations and materially increase operating and capital costs.
The loss of key personnel could adversely affect our ability to operate.
We depend, and will continue to depend in the foreseeable future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience and expertise in:
•
evaluating and analyzing drilling prospects and producing oil and gas from proved properties; and
•
maximizing production from oil and natural gas properties.
Our ability to retain our senior officers, other key employees and our third party consultants, none of whom are subject to employment agreements with us, is important to our future success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business.
Hedging our production may expose us to various risks.
While we do not currently engage in hedging activities, in the future we may enter into hedging transactions to reduce our exposure to fluctuations in the market prices of oil and natural gas. These positions may also limit our potential profits if oil and natural gas prices were to rise significantly over the stated price in these contracts.
Hedging will expose us to risk of financial loss in some circumstances, including if:
•
production is delayed or less than expected;
•
the counterparty to the hedging contract is unable to satisfy its obligations; or
•
there is an adverse change in the expected differential between the underlying price in the hedging agreement and actual prices received for our production.
Additionally, the ability of the financial institution counterparties to our hedging contracts to meet their obligations under such contracts may be adversely affected by market conditions. This may expose us to additional risks in realizing any benefits associated with our hedge positions. The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy.
We may not be able to obtain the necessary financing to complete the development of the Main Pass Energy Hub™ (MPEH™) project, and once operational, the MPEH™ project would be subject to certain risks.
Currently our subsidiary, Freeport-McMoRan Energy LLC, and a third party are engaged in efforts to utilize the MPEH™ as a potential deepwater port facility/terminal to receive, store, condition and liquefy domestic natural gas for export as LNG. Should we decide to pursue this facility, we may not be able to obtain the necessary financing to complete its development and any such financing may be limited by restrictions contained in our existing financing agreements, or the financial, commodity and credit markets generally. Additionally, the MPEH™ project, once operational, would be subject to significant operating hazards and uninsured risks, one or more of which may create significant liabilities for us.
Risks Relating to the FCX/MMR Merger
The requisite stockholder votes required to approve the FCX/MMR merger may not be obtained.
The completion of the FCX/MMR merger is subject to a number of conditions, including the approval of the FCX/MMR merger proposal by a majority of the outstanding shares of our common stock, excluding shares owned by FCX and its subsidiaries, PXP and its subsidiaries, and certain of our executive officers and directors who also serve as officers and/or directors of FCX, specifically, Richard C. Adkerson, Robert A. Day, Gerald J. Ford, H. Devon Graham, Jr., James R. Moffett, Nancy D. Parmelee, Kathleen L. Quirk and B. M. Rankin, Jr., (the majority of the disinterested stockholder approval). As such, even if a majority of the outstanding shares of our common stock vote in favor of the merger agreement, the FCX/MMR merger will not be consummated if the majority of the disinterested stockholder approval is not obtained.
The FCX/MMR merger is subject to conditions, including certain conditions that may not be satisfied, and may not be completed on a timely basis, or at all. Failure to complete the FCX/MMR merger could have material and adverse effects on us.
The completion of the FCX/MMR merger is subject to a number of conditions, including the majority of the disinterested stockholder approval of the merger proposal, which make the completion and timing of the completion of the FCX/MMR merger uncertain.
If the FCX/MMR merger is not completed on a timely basis, or at all, our ongoing businesses may be adversely affected and, without realizing any of the benefits of having completed the FCX/MMR merger, we will be subject to a number of risks, including the following:
•
we may be required to pay to FCX, in certain circumstances, an expense reimbursement fee of up to $19.5 million or a termination fee equal to $98 million;
•
time and resources committed by our management to matters relating to the FCX/MMR merger could otherwise have been devoted to pursuing other beneficial opportunities;
•
the market price of our common stock could decline to the extent that the current market price reflects a market assumption that the FCX/MMR merger will be completed;
•
if the FCX/MMR merger agreement is terminated and our board of directors seeks another business combination, our stockholders cannot be certain that we will be able to find a party willing to enter into a merger agreement on terms equivalent to or more attractive than the terms to which FCX has agreed;
•
the interim covenants in the merger agreement that restrict us from taking certain specified actions while the FCX/MMR merger is pending may prevent us from pursuing otherwise attractive business opportunities and making other changes to our business prior to completion of the FCX/MMR merger or termination of the merger agreement. Because we do not expect to complete the FCX/MMR merger until the second quarter of 2013, we are expecting to operate under these restrictions for a significant period of time; and
•
uncertainty regarding the completion of the FCX/MMR merger may foster uncertainty among employees about their future roles, which could adversely affect our ability to attract and retain key management, sales, marketing, trading and technical personnel;
Putative stockholder class actions challenging the FCX/MMR merger have been filed against us and the members of our board of directors, FCX and the members of its board of directors, INAVN Corp. and PXP, and an unfavorable judgment or ruling in any of these lawsuits could prevent or delay the consummation of the FCX/MMR merger and result in substantial costs.
Putative class and derivative actions challenging the FCX/MMR merger have been filed on behalf of our stockholders and FCX stockholders in the Court of Chancery of the State of Delaware, the Civil District Court for the Parish of Orleans of the State of Louisiana and in the Superior Court of the State of Arizona, County of Maricopa. The defendants in these lawsuits include us, the members of our board of directors, FCX, certain members of its boards of directors and/or officers, PXP, certain members of its boards of directors and/or officers, Gulf Coast Ultra Deep Royalty Trust, INAVN Corp., a wholly-owned subsidiary of FCX. The plaintiffs seek as relief, among other things, an injunction barring or rescinding the FCX/MMR merger and damages. If a final settlement is not reached, or if dismissals are not obtained, these lawsuits could prevent or delay completion of the FCX/MMR merger and result in substantial costs to us, FCX and PXP, including any costs associated with the indemnification of our directors. Additional lawsuits related to the FCX/MMR merger may be filed against us, FCX and PXP, their respective affiliates and our directors.
If FCX consummates the FCX/PXP merger, failing to complete the FCX/MMR merger could have consequences under the Clayton Antitrust Act and negatively affect our future businesses and financial results.
If the FCX/PXP merger is completed and the FCX/MMR merger is not completed, then our board of directors and executive management and the board of directors and executive management of FCX may need to be reconstituted in order to comply with the Clayton Antitrust Act (15 U.S.C. § 19) (the Clayton Act). Subject to certain de minimis exceptions, Section 8 of the Clayton Act prohibits individuals from serving as directors or officers of two competing corporations when each corporation has capital, surplus and undivided profits in excess of $27,784,000. Currently, we and FCX share overlapping board and management members, an overlap that is expected to continue even after the FCX/PXP merger is consummated. In the event that the FCX/PXP merger closes without the FCX/MMR merger also closing, the DOJ or FTC could investigate whether we and FCX are competitors for purposes of the Clayton Act, and could seek to eliminate the interlock by securing resignation of the interlocked individuals or by pursuing injunctive relief. Private plaintiffs could also bring suits against the combined company following the FCX/PXP merger seeking an injunction against the interlock. The potential distraction from operations, loss of key executive talent and cost of litigation could adversely affect our business, financial condition or result of operations.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 3.
Item 3. Legal Proceedings
We may from time to time be involved in various legal proceedings of a character normally incident to the ordinary course of our business. We believe that potential liability from any of these pending or threatened proceedings will not have a material adverse effect on our financial condition or results of operations. We maintain liability insurance to cover some, but not all, of the potential liabilities normally incident to the ordinary course of our businesses as well as other insurance coverages customary in our business, with coverage limits as we deem prudent. See Note 15, which is incorporated herein by reference, for further description of our legal proceedings.
Item 4.
Item 4. Mine Safety Disclosures
Not applicable.
Executive Officers of the Registrant
Listed below are the names and ages, as of January 31, 2013, of the present executive officers of McMoRan together with the principal positions and offices with McMoRan held by each.
James R. Moffett has served as our Co-Chairman of the Board since November 1998 and our President and Chief Executive Officer since May 2010. Mr. Moffett has also served as the Chairman of the Board of FCX since May 1992, and previously served as Chief Executive Officer of FCX from July 1995 to December 2003. Mr. Moffett’s technical background is in geology and he has been actively engaged in petroleum geological activities in the areas of our company’s operations throughout his business career. He is also founder of our predecessor company.
Richard C. Adkerson has served as our Co-Chairman of the Board since November 1998. He previously served as our President and Chief Executive Officer from November 1998 to February 2004. Mr. Adkerson has also served as a director of FCX since October 2006, Chief Executive Officer of FCX since December 2003, and as President of FCX since January 2008 and previously from April 1997 to March 2007 and previously served as Chief Financial Officer of FCX from October 2000 to December 2003.
Nancy D. Parmelee has served as our Senior Vice President and Chief Financial Officer since August 1999. She was appointed as Secretary of the company in January 2000. Ms. Parmelee has also served as Vice President of FCX since April 2003.
Kathleen L. Quirk has served as our Senior Vice President since April 2002 and Treasurer since January 2000. Ms. Quirk currently serves as Executive Vice President, Chief Financial Officer and Treasurer of FCX, and has held those offices since March 2007, December 2003 and February 2000, respectively. She also previously served as Senior Vice President of FCX from December 2003 to March 2007.
PART II
Item 5.
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is listed on the New York Stock Exchange (NYSE) under the symbol “MMR.” The following table sets forth, for the period indicated, the range of high and low sales prices, as reported by the NYSE.
As of January 31, 2013 there were 6,543 holders of record of our common stock. We have not in the past paid, and do not anticipate in the future paying, cash dividends on our common stock. Currently, our debt agreements prohibit our payment of dividends on our common stock. At such time, if ever, that such restrictions are lifted, the Board of Directors has the sole discretion as to the timing and amount of any cash dividends.
Issuer Purchases of Equity Securities
In 1999, our Board of Directors approved an open market share purchase program for up to 2.0 million shares of our common stock. In 2000, the Board of Directors authorized the purchase of up to an additional 0.5 million shares under the program. The program has no expiration date. No shares were purchased during the three years ending December 31, 2012. Approximately 0.3 million shares remain available for purchase under the program.
Performance Graph
The information included under the caption “Performance Graph” in this Item 5 of this Form 10-K is not deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C under the Securities Exchange Act of 1934 or to the liabilities of Section 18 of the Securities Exchange Act of 1934, and will not be deemed to be incorporated by reference into any filings we make under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent we specifically incorporate it by reference into such a filing.
The following graph compares the change in the cumulative total stockholder return on our common stock with the cumulative total return of an Independent Oil & Gas Industry Group and the S&P Stock Index from 2008 through 2012. This comparison assumes $100 invested on December 31, 2007 in (1) our common stock, (2) an Independent Oil & Gas Industry Group, and (3) the S&P 500 Stock Index.
Comparison of Cumulative Total Return*
McMoRan Exploration Co., Independent
Oil & Gas Industry Group and S&P 500 Stock Index
_______________
* Total Return Assumes Reinvestment of Dividends
Unregistered Sales of Equity Securities
During 2012, 1,917 shares of McMoRan’s 8% preferred stock were converted with a liquidation preference of $1.9 million into approximately 0.3 million shares of McMoRan common stock (at a conversion rate equal to 146.1454 shares of common stock per share of 8% preferred stock). Following this transaction, 12,082 shares of McMoRan’s 8% preferred stock remain outstanding. These conversions were exempt from registration by virtue of the exemption provided under Section 3(a)(9) of the Securities Act.
Item 6.
Item 6. Selected Financial Data
The following table sets forth our selected audited historical financial and unaudited operating data for each of the five years in the period ended December 31, 2012. The historical information shown in the table below may not be indicative of our future results. You should read the information below together with Items 7. and 7A. “Management’s Discussion and Analysis of Financial Condition and Results of Operations and Qualitative and Quantitative Disclosures About Market Risk” and Item 8.
Item 8. Financial Statements and Supplementary Data
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and effected by the Company’s Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:
·
Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the Company’s assets;
·
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
·
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Our management, including our principal executive officer and principal financial officer, assessed the effectiveness of our internal control over financial reporting as of the end of the fiscal year covered by this annual report on Form 10-K. In making this assessment, our management used the criteria set forth in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our management’s assessment, management concluded that, as of the end of the fiscal year covered by this annual report on Form 10-K, our Company’s internal control over financial reporting is effective based on the COSO criteria.
Ernst & Young LLP, an independent registered public accounting firm, who audited the Company’s consolidated financial statements included in this Form 10-K, has issued an attestation report on the Company’s internal control over financial reporting, which is included herein.
James R. Moffett
Nancy D. Parmelee
Co-Chairman of the Board,
Senior Vice President,
President and Chief Executive Officer
Chief Financial Officer and
Secretary
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TO THE STOCKHOLDERS AND BOARD OF DIRECTORS
OF McMoRan EXPLORATION CO.:
We have audited McMoRan Exploration Co.’s (McMoRan) internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). McMoRan’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, McMoRan Exploration Co. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of McMoRan Exploration Co. as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income (loss), cash flow, and changes in stockholders’ equity for each of the three years in the period ended December 31, 2012, and our report dated February 22, 2013 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
New Orleans, Louisiana
February 22, 2013
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TO THE STOCKHOLDERS AND BOARD OF DIRECTORS
OF McMoRan EXPLORATION CO.:
We have audited the accompanying consolidated balance sheets of McMoRan Exploration Co. as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income (loss), cash flows, and changes in stockholders’ equity for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of McMoRan Exploration Co. at December 31, 2012 and 2011, and the consolidated results of its operations and its cash flow for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), McMoRan Exploration Co.’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2013, expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
New Orleans, Louisiana
February 22, 2013
McMoRan EXPLORATION CO.
CONSOLIDATED BALANCE SHEETS
McMoRan EXPLORATION CO.
CONSOLIDATED BALANCE SHEETS
(Continued)
The accompanying notes are an integral part of these consolidated financial statements.
McMoRan EXPLORATION CO.
CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these consolidated financial statements.
McMoRan EXPLORATION CO.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
The accompanying notes are an integral part of these consolidated financial statements.
McMoRan EXPLORATION CO.
CONSOLIDATED STATEMENTS OF CASH FLOW
McMoRan EXPLORATION CO.
CONSOLIDATED STATEMENTS OF CASH FLOW
(Continued)
The accompanying notes are an integral part of these consolidated financial statements.
McMoRan EXPLORATION CO.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
McMoRan EXPLORATION CO.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
(Continued)
The accompanying notes are an integral part of these consolidated financial statements.
McMoRan EXPLORATION CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation. The consolidated financial statements of McMoRan Exploration Co. (McMoRan), a Delaware corporation, are prepared in accordance with U.S. generally accepted accounting principles. McMoRan’s consolidated financial statements include the accounts of those subsidiaries where McMoRan directly or indirectly has more than 50 percent of the voting rights and where the right to participate in significant management decisions is not shared with other stockholders, including its two wholly owned subsidiaries, McMoRan Oil & Gas LLC (MOXY) and Freeport-McMoRan Energy LLC (Freeport Energy). MOXY conducts all of McMoRan’s oil and gas operations. The long-term business objective of Freeport Energy is to maximize the value of the offshore structures used in the former sulphur operations, which currently includes the pursuit of a potential deepwater port facility/terminal to receive, store and condition natural gas for offloading to floating liquefaction storage and offloading vessels for export at the Main Pass Energy Hub TM (MPEH™) located at Main Pass Block 299 (Main Pass).
McMoRan’s investments in unincorporated legal entities represented by undivided interests in other oil and gas joint ventures and partnerships engaged in oil and gas exploration, development and production activities are pro rata consolidated, whereby a proportional share of each joint venture’s and partnership’s assets, liabilities, revenues and expenses are included in the accompanying consolidated financial statements in accordance with McMoRan’s working and net revenue interests in each joint venture and partnership.
All significant intercompany transactions have been eliminated. Changes in the accounting principles applied during 2012, none of which impacted the consistency of presentation, are discussed below under the caption “New Accounting Standards.”
McMoRan’s previously discontinued sulphur operations are presented as such, and the major classes of assets and liabilities related to its former sulphur business are separately shown for the periods presented.
Nature of Operations. McMoRan is an oil and gas exploration and production company engaged directly through its subsidiaries, joint ventures or partnerships with other entities in the exploration, development, production and marketing of crude oil and natural gas. McMoRan’s operations are located entirely in the United States, offshore in the Gulf of Mexico and onshore in the Gulf Coast region (primarily Louisiana and Texas).
McMoRan’s production of oil and natural gas involves lifting oil and natural gas to the surface and gathering, treating and processing hydrocarbons to extract liquids (primarily ethane, propane, butane and natural gasolines) from natural gas. McMoRan’s production costs include all costs incurred to operate or maintain its wells and related equipment and facilities. Examples of these costs include:
·
labor costs to operate the wells and related equipment and facilities;
·
repair and maintenance costs, including costs associated with re-establishing production from a geological structure that has previously produced;
·
material, supplies, and fuel consumed and services utilized in operating the wells and related equipment and facilities, including marketing and transportation costs; and
·
property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
Use of Estimates. The preparation of McMoRan’s financial statements in conformity with U.S. generally accepted accounting principles require management to make estimates and assumptions that affect the amounts reported in these consolidated financial statements and the accompanying notes to the consolidated financial statements. The more significant estimates include reclamation and environmental obligations, useful lives for depletion, depreciation and amortization, estimates of proved oil and natural
gas reserves and related future cash flows and the carrying value of long-lived assets and assets held for sale or disposal. Actual results could differ from those estimates.
Cash and Cash Equivalents. Highly liquid investments purchased with an original maturity of three months or less are considered cash equivalents (excluding certain restricted cash, Note 15).
Accounts Receivable. The majority of McMoRan’s accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. McMoRan’s counterparty credit losses have historically been minimal.
Inventories. Product inventories totaled $0.8 million at December 31, 2012 and $1.3 million at December 31, 2011, consisting of crude oil production from Main Pass. Materials and supplies inventory totaled $27.7 million at December 31, 2012 and $34.9 million at December 31, 2011 and represents the cost of supplies to be used in McMoRan’s drilling activities, primarily drilling pipe and tubulars. A portion of the cost of such inventory will be reimbursed to McMoRan by joint operating partners as future well drilling activity utilizes these materials. McMoRan’s inventories are stated at the lower of weighted average cost or market. During 2012 McMoRan reduced the carrying value of its inventories by approximately $2.8 million to reflect its determination of items that were deemed to have no future utility. There were no required reductions in the carrying value of McMoRan’s inventories during 2011 or 2010.
Property, Plant and Equipment.
Oil and Gas. McMoRan follows the successful efforts method of accounting for its oil and natural gas exploration and development activities. Costs associated with drilling and development activities are included as a use of investing cash flow in the accompanying consolidated statements of cash flow.
·
Geological and geophysical costs and costs of retaining unproved properties and undeveloped properties are charged to expense as incurred and are included as a use of operating cash flow in the accompanying consolidated statements of cash flow.
·
Costs of exploratory wells are capitalized pending determination of whether they have discovered proved reserves.
*
The costs of exploratory wells that have found oil and natural gas reserves that cannot be classified as proved when drilling is completed, continue to be capitalized as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well and sufficient progress is being made in assessing the proved reserves and the economic and operating viability of the project. Management evaluates progress on such wells on a quarterly basis.
*
Drilling costs that no longer meet the criteria for continued capitalization under U.S. generally accepted accounting principles, but for which management intends to pursue development activities, are charged to depletion, depreciation and amortization expense.
*
If proved reserves are not discovered, the related drilling costs are charged to exploration expense.
·
Acquisition costs of leases and development activities are capitalized.
·
Other exploration costs are charged to expense as incurred.
·
Depletion, depreciation and amortization expense is determined on a field-by-field basis using the units-of-production method, with depletion, depreciation and amortization rates for leasehold acquisition costs based on estimated proved reserves and depletion, depreciation and amortization rates for well and related facility costs based on proved developed reserves associated with each field. The depletion, depreciation and amortization rates are revised whenever required but, at a minimum, are assessed semi-annually. Any such revisions are accounted for prospectively as a change in accounting estimate.
·
The costs of maintenance and repairs are expensed when incurred.
·
Gains or losses from dispositions of McMoRan’s interests in oil and gas properties are included in earnings under the following conditions:
*
All or part of an interest owned is sold to an unrelated third party; if only part of an interest is sold, there is no substantial uncertainty about the recoverability of cost applicable to the interest retained; and
*
McMoRan has no substantial obligation for future performance (e.g. drilling a well(s) or operating the property without proportional reimbursement of costs relating to the interest sold).
·
Interest expense allocable to significant unproved leasehold costs and in progress exploration and development projects is capitalized until the assets are ready for their intended use. Interest expense capitalized by McMoRan totaled $56.5 million in 2012, $47.4 million in 2011 and $10.1 million in 2010.
Sulphur. Note 11 includes results associated with McMoRan’s discontinued operations, which are reflected within the caption “Loss from discontinued operations” in the accompanying consolidated statements of operations. McMoRan’s remaining sulphur property, plant and equipment is carried at the lower of cost or estimated net realizable value.
Asset Impairment. Costs of unproved oil and gas properties are assessed periodically and a loss is recognized if the properties are deemed impaired. When events or circumstances indicate that proved oil and gas property carrying amounts might not be recoverable from estimated future undiscounted cash flows, a reduction of the carrying amount to estimated fair value is required. McMoRan estimates the fair value of its properties (derived from Level 3 inputs) using estimated future cash flows based on proved and risk-adjusted probable oil and natural gas reserves as estimated by independent reserve engineers. Future cash flows are determined using published period-end forward market prices adjusted for property-specific price basis differentials, net of estimated future production and development costs and excluding estimated asset retirement and abandonment expenditures. If the undiscounted cash flows indicate that the property is impaired, McMoRan discounts the future cash flows using a discount factor that considers market participants’ expected rates of return for similar type assets if acquired under current market conditions.
The determination of oil and gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Subsequent evaluation of the same reserves may result in variations in estimated reserves and related estimates of future cash flows, and these variations may be substantial. If the capitalized costs of an individual oil and gas property exceed the related estimated future net cash flows, an impairment charge to reduce the capitalized costs to the property’s estimated fair value is required (Note 5).
Revenue Recognition and Gas Balancing. McMoRan generally sells crude oil and natural gas under short-term agreements at prevailing market prices. Revenue for the sale of crude oil and natural gas is recognized when title passes to the customer, when prices are fixed or determinable and collection is reasonably assured. Natural gas revenues involving partners in natural gas wells are recognized when the natural gas is sold using the entitlements method of accounting and are based on McMoRan’s net working interests. When McMoRan receives a volume in excess of its net working interests, it records a liability and under deliveries are recorded as receivables. At December 31, 2012, McMoRan had natural gas imbalance receivables valued at $2.6 million for under deliveries and liabilities valued at $3.4 million for over deliveries. At December 31, 2011, McMoRan had natural gas imbalance receivables valued at $4.2 million for under deliveries and liabilities valued at $4.6 million for over deliveries.
Service Revenue. McMoRan records the gross amount of reimbursements for costs from third parties as service revenues whenever McMoRan is the primary obligor with respect to the source of such costs, has discretion in the selection of how the related service costs are incurred and when it has assumed the credit risk associated with the reimbursement for such service costs. The service costs associated with
these third-party reimbursements are also recorded within the applicable cost and expense line item in the accompanying consolidated financial statements.
McMoRan’s service revenues have been generated primarily through fees for processing
third-party oil and gas production, other third party management fees and standardized industry (COPAS) overhead charges McMoRan receives as operator of oil and gas properties.
Reclamation and Closure Costs. McMoRan incurs costs for environmental programs and projects. Expenditures pertaining to future revenues from operations are capitalized. Expenditures resulting from the remediation of conditions caused by past operations that do not contribute to future revenue generation are charged to expense. Liabilities are recognized for remedial activities when the efforts are probable and the costs can be reasonably estimated. Reclamation cost estimates are by their nature imprecise and can be expected to be revised over time because of a number of factors, including changes in reclamation plans, cost estimates, governmental regulations, technology and inflation.
McMoRan uses estimates derived from information provided by in-house engineers and third-party specialists in determining its estimated asset retirement obligations under multiple probability-assessed scenarios reflecting a range of possible outcomes considering the future costs to be incurred, the scope of work to be performed and the timing of such expenditures (Note 15).
Comprehensive Loss. McMoRan follows U.S. generally accepted accounting principles for the reporting and display of comprehensive loss (net loss adjusted for other comprehensive income (loss), or all other changes in net assets from nonowner sources) and its components.
Financial Instruments and Contracts. Based on its assessment of market conditions, McMoRan may enter into financial contracts to manage certain risks resulting from fluctuations in oil and natural gas prices. Costs or premiums and gains or losses on contracts meeting deferral criteria are recognized with the hedged transactions. Also, gains or losses are recognized if the hedged transaction is no longer expected to occur or if deferral criteria are not met. McMoRan monitors any related counterparty credit risk on an ongoing basis and considers this risk to be minimal.
In connection with the 2007 oil and gas property acquisition, MOXY entered into oil and gas derivative contracts for a portion of its anticipated production for the years 2008 through 2010. The oil and gas derivative contracts were not designated as hedges for accounting purposes. Accordingly, these contracts were subject to mark-to-market fair value adjustments, the impact of which was recognized immediately in McMoRan’s operating results. McMoRan recorded all gains and losses associated with these derivative contracts within a separate line in the accompanying consolidated statements of operations, and any related cash flow effect was recorded within cash flows from operations in the related consolidated statements of cash flow. McMoRan believes the operating presentation of its oil and gas derivatives contracts is appropriate in both its statements of operations and cash flow because the sale of oil and natural gas production represents the primary source of its operating income and cash flow. All remaining derivative contract positions matured on December 31, 2010 (Note 8).
Earnings Per Share. Basic net loss per share of common stock is calculated by dividing the loss applicable to continuing operations, the loss from discontinued operations, and the net loss applicable to common stock by the weighted-average number of common shares outstanding during the periods presented. For purposes of the basic earnings per share computations, the net loss applicable to continuing operations includes preferred stock dividends and related charges (Notes 9 and 10).
Stock-Based Compensation. Compensation cost recognized includes compensation cost for all stock option awards granted based on the grant-date fair value and restricted stock units granted which are estimated in accordance with U.S. generally accepted accounting principles. McMoRan recognizes compensation costs for awards that vest over several years on a straight-line basis over the vesting period. McMoRan’s stock-based awards provide for an additional year of vesting after an employee retires. For awards to retirement-eligible employees, McMoRan records one year of amortization of the awards’ estimated fair value on the date of grant because the grantee has earned that one year vesting benefit under the terms of McMoRan’s stock options plans based on length of service. McMoRan includes estimated forfeitures in its compensation cost and updates the estimated forfeiture rate through the final vesting date of the awards (Note 12).
McMoRan currently recognizes no income tax benefits for deductions resulting from the exercise of stock options because all of its net deferred tax assets, including significant net operating loss carryforwards, have been reserved with a full valuation allowance (Note 13).
New Accounting Standard. In June 2011, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) in connection with guidance on the presentation of comprehensive income. The objective of this ASU is to improve the comparability, consistency and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. This ASU requires an entity to present the components of net income and other comprehensive income and total comprehensive income (includes net income) either in a single continuous statement of comprehensive income or in two separate but consecutive statements. This ASU eliminates the option to present the components of other comprehensive income as part of the statement of equity, but does not change the items that must be reported in other comprehensive income. McMoRan adopted this ASU and presented total comprehensive income in a separate statement for all periods reported in these financial statements.
2. DEFINITIVE MERGER AGREEMENT
On December 5, 2012, McMoRan announced a definitive agreement (the merger agreement) under which Freeport-McMoRan Copper & Gold Inc. (FCX) will acquire McMoRan for approximately $3.4 billion in cash, or $2.1 billion net of the 36 percent ownership interest currently held by FCX and Plains Exploration & Production Company (PXP) (the FCX/MMR merger). The related per-share consideration consists of $14.75 in cash and 1.15 units in the Gulf Coast Ultra Deep Royalty Trust, a newly formed royalty trust, which will hold a five percent overriding royalty interest in future production from McMoRan’s ultra-deep prospects. Completion of the FCX/MMR merger is subject to stockholder approval, regulatory approvals (including U.S. antitrust clearance under the Hart-Scott-Rodino Act), and other customary conditions. On December 26, 2012, the U.S. Federal Trade Commission granted early termination of the Hart-Scott-Rodino waiting period. The FCX/MMR merger is expected to close in second-quarter 2013 (Note 2).
Also on December 5, 2012, FCX announced a definitive merger agreement under which FCX will acquire PXP for approximately $6.9 billion in cash and stock (the FCX/PXP merger). The FCX/PXP merger is subject to the approval of PXP’s stockholders, receipt of regulatory approvals and customary closing conditions. On December 5, 2012, PXP owned 51 million shares of McMoRan common stock, which they acquired in December 2010 as part of an asset acquisition transaction with McMoRan (Note 3).
Substantial capital expenditures have been and will continue to be required in McMoRan’s exploration and development activities, especially for the development and exploitation of its significant ultra-deep exploration and development projects. McMoRan’s capital expenditures have been financed in part with internally generated cash from operations, the continued availability of which is dependent on a number of variables including production from its existing proved reserves, sales prices for natural gas and oil, and its ability to acquire, locate and produce new reserves. McMoRan has also financed its capital expenditures with proceeds from debt and equity financings and participation by partners in exploration and development projects. McMoRan’s ongoing exploration and development activities require substantial financial resources, which it believes can be met following completion of the transaction with FCX discussed above (FCX/MMR merger). Should the FCX/MMR merger not occur, McMoRan expects to continue to financially support its near-term operating requirements and a limited capital expenditure budget with cash on hand, internally generated cash from operations and if required, potential asset sales, joint venture transactions or other financings. On a standalone basis, McMoRan would require additional capital to continue its aggressive drilling and development program, which may include potential asset sales, additional debt or equity financings, joint venture transactions or other financing arrangements.
3. ACQUISITIONS AND DIVESTITURES OF OIL AND GAS PROPERTIES
On November 13, 2012 McMoRan completed the sale of a package of Gulf of Mexico traditional shelf oil and gas properties in the Eugene Island area (the Eugene Island Assets), for net cash consideration of $29.8 million (after closing adjustments) and the assumption of related abandonment obligations. The Eugene Island Assets represented approximately six percent of McMoRan’s total average daily
production for the third quarter of 2012 and six percent of its total estimated reserves at June 30, 2012. Independent reserve engineers’ estimates of proved reserves for the Eugene Island Assets at June 30, 2012 approximated 15.2 billion cubic feet of natural gas equivalents, with approximately 78 percent from natural gas and 21 percent proved developed producing. The transaction was effective July 1, 2012.
On October 2, 2012, McMoRan completed the sale of three Gulf of Mexico shelf oil and gas properties in the West Delta and Mississippi Canyon areas (the Assets) for net cash consideration of $26.1 million (after closing adjustments) and the assumption of related abandonment obligations. The Assets represented approximately one percent of McMoRan’s total average daily production for the third quarter of 2012 and three percent of its total estimated reserves at June 30, 2012. Independent reserve engineers’ estimates of proved reserves for the Assets at June 30, 2012, approximated 942,000 barrels of oil and 1.7 billion cubic feet of natural gas (7.4 billion cubic feet of natural gas equivalents). The transaction was effective July 1, 2012.
The combined net cash proceeds from the 2012 divestiture transactions referred to above totaled $55.9 million and assumed reclamation obligations totaled $45.6 million. McMoRan recorded net gains totaling $39.7 million in the fourth quarter of 2012 in connection with these transactions.
On September 8, 2011, McMoRan acquired Whitney Exploration LLC’s (Whitney) 2.97% working interest in Davy Jones and 2% working interest in Blackbeard East. Under the terms of the transaction, McMoRan issued approximately 2.8 million shares of its common stock and paid $10 million in cash to Whitney for these interests relating to drilling projects in process. McMoRan’s common stock price on the closing date was $12.36 per share. The fair value of the interests acquired approximated $49 million. The acquisition of Whitney’s interests had no material impact to McMoRan’s statements of operations on a pro forma basis.
On December 30, 2010, McMoRan completed the $1 billion acquisition of PXP’s shallow water Gulf of Mexico shelf assets (PXP Acquisition). Under the terms of the transaction, McMoRan issued 51 million shares of its common stock and paid $75.0 million in cash to PXP. In addition, the purchase price included $45.5 million associated with estimated revenues, expenses and capital expenditures attributable to the properties from the August 1, 2010 effective date through the December 30, 2010 closing date, and the assumption of approximately $8.8 million of related asset retirement obligations. The substantial majority of properties acquired from PXP represented their interests in certain deep gas and ultra-deep exploration projects that were jointly owned by McMoRan and PXP prior to the transaction. McMoRan incurred approximately $9.4 million in transaction related costs for the PXP Acquisition included in general and administrative expenses. Concurrent with the PXP Acquisition, McMoRan issued $700 million of 5.75% Convertible Perpetual Preferred Stock (5.75% preferred stock) and $200 million of 4% Convertible Senior Notes (4% convertible notes) to certain investors (Notes 7 and 9).
Subsequent Events
On January 28, 2013, McMoRan completed the sale of certain properties in the Breton Sound area to Century Exploration New Orleans, LLC (Century). Consideration consisted of the assumption of related abandonment obligations by Century of approximately $4.6 million and payment by McMoRan to Century of $0.6 million in cash (the Century Sale). The Century Sale properties represented approximately two percent of McMoRan’s total average daily production for the fourth quarter of 2012 and less than one percent of its total estimated reserves at December 31, 2012. Independent reserve engineers’ estimates of proved reserves for the Century Sale properties at December 31, 2012 totaled approximately 16,600 barrels of oil and natural gas liquids and 0.4 billion cubic feet of natural gas (0.5 billion cubic feet of natural gas equivalents). As of December 31, 2012 the estimated present value of future net cash flows discounted 10 percent (PV-10) was negative. The Century Sale was effective October 1, 2012.
On January 17, 2013, McMoRan completed the sale of its Laphroaig field to Energy XXI Limited for cash consideration, after closing adjustments, of $80 million and the assumption of approximately $0.6 million of related abandonment obligations. The Laphroaig field represented approximately 10 percent of McMoRan’s total average daily production for the fourth quarter 2012 and four percent of McMoRan’s total estimated reserves at December 31, 2012. Independent reserve engineers’ estimates of proved reserves for the Laphroaig field at December 31, 2012 approximated 101,000 barrels of oil and 8.7 billion
cubic feet of natural gas (9.4 billion cubic feet of natural gas equivalents). The transaction was effective January 1, 2013. McMoRan may consider additional sales of noncore assets during 2013.
McMoRan expects to record gains totaling approximately $76.6 million in the first quarter of 2013 in connection with the Century Sale and the sale of the Laphroaig field.
4. ACCOUNTS RECEIVABLE AND MAJOR CUSTOMERS
The components of accounts receivable follow (in thousands):
Sales of McMoRan’s oil and natural gas production to individual customers representing 10 percent or more of its total consolidated oil and gas revenues in each of the three years in the period ended December 31, 2012 is as follows:
All of McMoRan’s customers are located in the United States. McMoRan does not believe the loss of any of these purchasers would have a material adverse effect on its operations because oil and gas is a commodity in demand and alternative purchasers, if needed, are readily available.
5. PROPERTY, PLANT AND EQUIPMENT
The components of net property, plant and equipment follow (in thousands):
The components of McMoRan’s depletion, depreciation and amortization expense are summarized below (in thousands):
As discussed in Note 1, when events and circumstances indicate that proved oil and gas property carrying amounts might not be recoverable from estimated future undiscounted cash flows, a reduction of the carrying amount to estimated fair value is required.
McMoRan recorded impairment charges during the year ended December 31, 2012 of $46.2 million to reduce net carrying values of certain of its oil and gas properties to fair value primarily due to negative revisions to estimated proved undeveloped reserves for one property, well performance issues, higher than anticipated recompletion costs for a certain property, a decline in market prices earlier in 2012, and other economic factors (Note 15). During the year ended December 31, 2011 McMoRan recorded impairment charges of $71.1 million primarily due to well performance issues, the decline in market prices for natural gas, and the impact of increased capitalized costs from asset retirement obligation adjustments for certain properties, and during the year ended December 31, 2010 McMoRan recorded impairment charges of $107.2 million due largely to declines in market prices for natural gas during those years and, with respect to certain properties, as a result of negative reserve revisions from well performance issues.
As discussed above, declines in market prices for primarily natural gas coupled with other operational factors triggered impairment assessments that ultimately resulted in significant impairment charges for several of McMoRan’s oil and gas property investments. Additional impairment charges may be recorded in future periods if market conditions experienced in recent years continue to weaken, or if other unforeseen operational issues occur that negatively impact McMoRan’s ability to fully recover its current investments in oil and gas properties.
Insurance
Hurricanes Gustav and Ike impacted McMoRan’s Gulf of Mexico operations prior to making landfall on the Louisiana and Texas coasts in September 2008. Although there was no significant damage to McMoRan’s properties resulting from Hurricane Gustav, Hurricane Ike caused significant structural damage to several platforms in which McMoRan had an investment interest. From the third quarter of 2008 through 2011, McMoRan recorded charges of approximately $200 million related to repair costs, property impairments and additional estimated reclamation costs associated with the damaged properties. In December 2011, McMoRan reached a settlement with its insurance underwriters to finalize all outstanding claims from the 2008 hurricane events. Including final settlement amounts, McMoRan recorded cumulative insurance recoveries of $154.6 million relating to the 2008 hurricane events. During 2012, McMoRan recognized $1.2 million of insurance proceeds related to a separate property damage claim. McMoRan recognized net insurance recoveries of $91.1 million in 2011 and $38.9 million in 2010.
6. OTHER ASSETS AND OTHER LIABILITIES
McMoRan defers its financing costs associated with its debt instruments and amortizes the costs over the terms of the related instruments. The components of deferred financing costs follow (in thousands):
As of December 31, 2012, other long-term assets includes approximately $1.5 million of prepaid drilling rig costs which are amortized as a component of contractual rig charges over the term of the contract.
The components of other long-term liabilities follow (in thousands):
7. LONG-TERM DEBT
The components of McMoRan’s long-term debt follow (in thousands):
McMoRan’s scheduled debt maturities are $67.8 million in 2013; $300 million in 2014; none in 2015 or 2016; and $200 million in 2017.
Variable Rate Senior Secured Revolving Credit Facility
During 2011 McMoRan entered into a new variable rate senior secured revolving credit facility (credit facility). The credit facility matures on June 30, 2016, provided that the facility will mature on August 16, 2014 if McMoRan’s 11.875% senior notes are not redeemed or refinanced with senior notes with a term extending at least through 2016 by that date. The credit facility’s borrowing capacity is $150 million. There were no borrowings outstanding under the credit facility as of December 31, 2012, although a $100 million letter of credit (LOC) in favor of a third party beneficiary for reclamation surety was outstanding against the facility. In January 2013, McMoRan reached agreement with the beneficiary to suspend the LOC requirement through June 30, 2013.
Availability under the credit facility is subject to a borrowing base calculated from estimates of MOXY’s oil and natural gas reserves, which is subject to redetermination by its lenders semi-annually each April and October. In the fourth quarter of 2012, in connection with the semi-annual redetermination of McMoRan’s borrowing base, McMoRan’s lenders affirmed the $150 million borrowing base subject to a continuing priority lien on $35 million of cash deposited in a separate deposit account until the next redetermination (second quarter of 2013). In February 2013, after giving effect to McMoRan’s sale of its Laphroaig field in January 2013 (Note 3), the amount of cash required for the separate account deposit was increased to $60 million. Use of the cash is unrestricted; however, to the extent McMoRan uses any portion of the cash prior to completion of the next redetermination, the borrowing base would be reduced on a dollar for dollar basis. The credit facility is secured by (1) substantially all the oil and gas properties of MOXY and its subsidiaries and (2) a pledge of McMoRan’s ownership interest in MOXY and MOXY’s ownership interest in each of its wholly owned subsidiaries.
Interest on the credit facility currently accrues at London Interbank Offered Rate (LIBOR) plus 2.00 percent, subject to increases or decreases based on usage as a percentage of the borrowing base. Fees associated with the letters of credit and the unused commitment fee are also subject to increases or decreases in the same manner. There were no borrowings under the credit facility in 2012, 2011 or 2010.
Interest expense on the credit facility (including amortization of deferred financing costs and other facility fees) totaled $4.0 million in 2012, $4.3 million in 2011 and $6.2 million in 2010.
The credit facility contains covenants and other restrictions customary for oil and gas borrowing base credit facilities, including limitations on debt, liens, dividends, voluntary redemptions of debt, investments, asset sales and transactions with affiliates. In addition, the credit facility requires that McMoRan maintain certain financial tests, including a leverage test (Total Debt to EBITDAX, as those terms are defined in the credit facility, for the preceding four quarters), and a current ratio test (current assets to current liabilities, subject to certain adjustments as of the end of the quarter). McMoRan was in compliance with these covenants at December 31, 2012.
11.875% Senior Notes
On November 14, 2007, McMoRan completed the sale of $300 million of 11.875% senior notes
(11.875% notes). Net proceeds from the sale of the 11.875% notes of approximately $292 million were used, along with additional borrowings under the credit facility, to repay remaining amounts outstanding on a previous bridge loan after application of the net proceeds from the concurrent public offerings of shares of McMoRan’s common stock and 6¾% mandatory convertible preferred stock (Note 9). The 11.875% notes are due on November 15, 2014 and are unconditionally guaranteed on a senior basis by MOXY and its subsidiaries (Note 18). McMoRan may redeem some or all of the 11.875% notes at its option at stated redemption prices. The indenture governing the 11.875% notes contains restrictions, including restrictions on incurring debt, creating liens, selling assets and entering into certain transactions with affiliates. The covenants also restrict McMoRan’s ability to pay certain cash dividends on common stock, repurchase or redeem common or preferred equity, prepay subordinated debt and make certain investments. Interest expense on the senior notes during 2012, 2011 and 2010 totaled $36.8 million, including amortization of related deferred financing costs of $1.2 million in each of those years. The estimated fair value of the 11.875% notes (derived from level 2 inputs) was approximately $320.3 million at December 31, 2012 and $318.0 million at December 31, 2011.
4% Convertible Senior Notes
On December 30, 2010, McMoRan completed a private placement of $200 million of 4% convertible senior notes (4% convertible notes) due December 30, 2017 concurrent with the 5.75% convertible preferred stock offerings (Note 9) and the PXP Acquisition (Note 3). The 4% convertible notes are unsecured with semi-annual interest payments payable on February 15 and August 15 of each year. The 4% convertible notes are convertible, at the option of the holder at any time on or prior to maturity, into shares of McMoRan common stock at a conversion rate of 62.5 shares of McMoRan common stock, which is equal to an initial conversion price of $16.00 per share of McMoRan common stock per $1,000 principal amount of the notes. The conversion rate is subject to adjustment upon the occurrence of certain events. The 4% convertible notes are redeemable for cash by McMoRan beginning December 30, 2015 under certain conditions.
The terms of the 4% convertible notes were negotiated in September 2010, and the closing for the 4% convertible notes was contingent upon the approval by McMoRan’s stockholders of FCX’s investment in the 5.75% preferred stock offering (Note 9) and the PXP Acquisition. The Notes closed on December 30, 2010, the date of stockholder approval of the other concurrent transactions. Because the value of McMoRan’s common stock on the closing date ($17.18 per share) exceeded the conversion price ($16 per share) for the convertible notes issued, the 4% convertible notes included a beneficial conversion option. With respect to the 4% convertible notes, the intrinsic value of the beneficial conversion option was recognized as a $14.8 million debt discount and a $14.8 million increase to McMoRan’s additional paid-in-capital, which is being accreted through McMoRan’s earnings as adjustments to interest expense through the debt maturity date. McMoRan incurred approximately $1.6 million of debt issuance costs associated with the 4% convertible notes. The estimated fair value of the 4% convertible notes (derived from level 2 inputs) was approximately $224.7 million at December 31, 2012 and $232.6 million at December 31, 2011.
5¼% Convertible Senior Notes
On October 6, 2004, McMoRan completed a private placement of $140 million of 5¼% convertible senior notes due October 6, 2011 (2011 5¼% convertible notes). Net proceeds from the 2011 5¼% convertible notes, after fees and expenses, totaled $134.4 million, of which $21.2 million was used to purchase U.S.
government securities to be held in escrow to pay the first six semi-annual interest payments on the notes. The 2011 5¼% convertible notes are otherwise unsecured.
During 2008, McMoRan privately negotiated transactions to induce the conversion of $40.2 million of the 2011 5¼% convertible notes into approximately 2.4 million shares of McMoRan’s common stock. McMoRan paid an aggregate $1.7 million in cash to induce these conversions, which was reflected as non-operating expense in the consolidated statements of operations.
On October 6, 2011, McMoRan completed an offer to exchange up to $74.7 million aggregate principal amount of 2011 5¼% convertible notes. 2011 5¼% convertible notes in the principal amount of $68.2 million were tendered and accepted for exchange for an equal principal amount of newly issued 5¼% Convertible Senior Notes due October 6, 2012 (2012 5¼% convertible notes). McMoRan repaid $6.5 million of the remaining principal amount of 2011 5¼% convertible notes, which matured in accordance with their terms on October 6, 2011. The terms of the 2012 5¼% convertible notes were substantially the same as the terms of the 2011 5¼% convertible notes, except that the 2012 5¼% convertible notes had a maturity date of October 6, 2012. The impact of this exchange transaction, which was recorded as a modification of debt in the fourth quarter of 2011, resulted in the recognition of an approximate $2.6 million debt discount related to the fair value of the instruments’ embedded conversion option (derived from level 2 inputs) with discount accretion recorded as a component of interest expense over the one year term of the 2012 5¼% convertible notes. Debt modification accounting was applied to the 2011 note exchange transaction as the terms of the new notes were not substantially different from the terms of the previous notes exchanged.
On September 13, 2012, McMoRan completed an offer to exchange up to $68.2 million aggregate principal amount of 2012 5¼% convertible notes. 2012 5¼% convertible notes in the principal amount of $67.8 million were tendered and accepted for exchange for an equal principal amount of newly issued 5¼% Convertible Senior Notes due October 6, 2013 (2013 5¼% convertible notes). McMoRan repaid $0.3 million of the remaining principal amount of 2012 5¼% convertible notes, which matured in accordance with their terms on October 6, 2012. The terms of the 2013 5¼% convertible notes are substantially the same as the terms of the 2012 5¼% convertible notes, except that the 2013 5¼% convertible notes have a maturity date of October 6, 2013. The impact of this exchange transaction, which was recorded as a debt extinguishment in the third quarter of 2012, resulted in a loss on debt exchange of $6.0 million (derived from level 2 inputs). Debt extinguishment accounting was applied to the 2012 note exchange transaction as the change in fair value of the embedded conversion option between the previous notes exchanged and the new notes exceeded ten percent of the face value of the notes prior to the exchange.
Interest payments are payable on April 6 and October 6 of each year. The 5¼% notes are convertible at the option of the holder at any time prior to maturity into shares of McMoRan’s common stock at a conversion price of $16.575 per share. Since October 6, 2009, McMoRan had the option of redeeming the 5¼% notes for a price equal to 100 percent of the principal amount of the notes plus any accrued and unpaid interest on the notes prior to the redemption date, provided the closing price of McMoRan’s common stock exceeded 130 percent of the conversion price for at least 20 trading days in any consecutive 30-day trading period.
The estimated fair value of the 2013 5¼% convertible notes (derived from level 2 inputs) was $69.0 million at December 31, 2012 and the estimated fair value of the 2012 5¼% convertible notes was $73.6 million at December 31, 2011.
The fair value measures determined by McMoRan for purposes of its accounting and disclosures associated with its debt instruments are derived from inputs related to observable market transactions of instruments with comparable terms and similar issuer characteristics.
8. DERIVATIVE CONTRACTS
In connection with the closing of the 2007 oil and gas property acquisition and related financing, MOXY entered into derivative contracts for a portion of the anticipated production from its proved developed producing oil and gas properties at the time of the acquisition for the years 2008 through 2010.
Because these oil and gas derivative contracts were not designated as hedges for accounting purposes, unrealized (gains) losses representing changes in the related fair values along with realized (gains) losses representing cash settlements were recognized immediately in McMoRan’s operating results at the reporting period. McMoRan’s realized and unrealized (gains) losses on these contracts were as follows for the year ended December 31, 2010 (in thousands):
All remaining derivative contract positions matured on December 31, 2010.
9. COMMON STOCK AND PREFERRED STOCK OFFERINGS
On September 8, 2011, McMoRan issued approximately 2.8 million shares of its common stock in connection with acquiring Whitney’s working interests in Davy Jones and Blackbeard East, and on December 30, 2010, McMoRan issued 51 million shares of its common stock in connection with the PXP Acquisition (Note 3).
On December 30, 2010, McMoRan completed the private placement of $700 million of 5.75% convertible perpetual preferred stock (5.75% preferred stock) concurrent with the 4% senior note offering (Note 6) and the PXP Acquisition (Note 3). FCX, an affiliate of McMoRan (Note 14), purchased $500 million of the 5.75% preferred stock, and $200 million of the 5.75% preferred stock was purchased by institutional investors.
The 5.75% preferred stock is recorded at the liquidation preference value ($1,000 per share). Cumulative annual dividends accrue at 5.75% of the liquidation preference, payable quarterly on February 15, May 15, August 15 and November 15 of each year, which commenced on February 15, 2011. The 5.75% preferred stock is convertible, at the option of the holder, at any time into shares of McMoRan common stock at a conversion rate of 62.5 shares of McMoRan common stock per $1,000 liquidation preference of the 5.75% preferred stock, which is equal to an initial conversion price of $16.00 per share. The conversion rate is subject to adjustment upon the occurrence of certain events. On or after three years following the date of issuance, McMoRan may redeem some or all of the 5.75% preferred stock under certain conditions.
The terms of the 5.75% preferred stock were negotiated in September 2010 and closing for the transaction was subject to McMoRan stockholder approval. The transaction closed on December 30, 2010, the date of stockholder approval. Because the value of McMoRan’s common stock on the closing date ($17.18 per share) exceeded the conversion price ($16 per share) for the convertible instruments issued, the 5.75% preferred stock included a beneficial conversion option. The intrinsic value of the beneficial conversion option associated with the 5.75% preferred stock was recognized by McMoRan at the date of closing as a preferred stock discount and related preferred stock dividend resulting in a $51.6
million increase to additional paid-in-capital and a $51.6 million reduction to income applicable to common stockholders. McMoRan incurred approximately $5.7 million of offering costs associated with the 5.75% preferred stock.
In June 2009, McMoRan completed concurrent public offerings of 15.5 million shares of common stock at $5.75 per share and 86,250 shares of 8% convertible perpetual preferred stock (8% preferred stock) with an offering price of $1,000 per share. The net proceeds from these offerings, after deducting underwriters’ discounts and other expenses, were approximately $168.3 million.
The 8% preferred stock is recorded at the liquidation preference value ($1,000 per share), and dividends are paid quarterly. Each share of the 8% preferred stock is convertible into 146.1454 shares of McMoRan common stock (equivalent to a conversion price of $6.8425 per share), subject to certain anti-dilution adjustments. Beginning June 15, 2014, McMoRan has the right to redeem shares of the 8% preferred stock by paying cash, McMoRan common stock or any combination thereof for $1,000 per share plus accumulated and unpaid dividends, but only if the trading price of McMoRan’s common stock has exceeded 130% of the initial conversion price for at least 20 trading days within a period of 30 consecutive trading days ending on the trading day before the date McMoRan gives the redemption notice.
In 2010, McMoRan privately negotiated the induced conversion of approximately 64,200 shares of its 8% preferred stock with a liquidation preference of $64.2 million into approximately 9.4 million shares of McMoRan common stock (at a conversion rate equal to 146.1454 shares of common stock per share of 8% preferred stock). To induce the early conversions of the 8% preferred stock, McMoRan paid an aggregate of $12.2 million in cash and recorded such payments as preferred dividends.
In 2011, McMoRan privately negotiated the induced conversion of approximately 8,100 shares of its 8% preferred stock with a liquidation preference of $8.1 million into approximately 1.2 million shares of McMoRan common stock (at a conversion rate equal to 146.1454 shares of common stock per share of 8% preferred stock). To induce the early conversion of these shares of 8% preferred stock, McMoRan paid an aggregate of $1.5 million in cash and recorded such payments as preferred dividends.
During 2012, 1,917 shares of McMoRan’s 8% preferred stock were converted with a liquidation preference of $1.9 million into approximately 0.3 million shares of McMoRan common stock (at a conversion rate equal to 146.1454 shares of common stock per share of 8% preferred stock). At December 31, 2012, 12,082 shares of McMoRan’s 8% preferred stock remained outstanding.
10. EARNINGS PER SHARE
McMoRan had a net loss from continuing operations for each of the three years in the period ending December 31, 2012. Accordingly, McMoRan’s diluted per share calculation for these periods was equivalent to its basic net loss per share calculation because it excluded the assumed exercise of stock options whose exercise prices were less than the average market price of McMoRan’s common stock during these periods, as well as the assumed conversion of McMoRan’s 5.75% preferred stock, 8% preferred stock, 6¾% preferred stock, 4% convertible notes and 5¼% convertible notes. These instruments were excluded for these periods because they were considered to be anti-dilutive, meaning their inclusion would have reduced the reported net loss per share for these periods. The excluded common share amounts are summarized below (in thousands):
a.
McMoRan uses the treasury stock method to determine the amount of in-the-money stock options to include in its diluted earnings per share calculation.
b.
Represents stock options with an exercise price less than the average market price for McMoRan’s common stock for the periods presented.
c.
Amount represents total equivalent common stock shares assuming conversion of 5.75% preferred stock (Note 9). The 2010 amount is reduced from the total 43.8 million equivalent shares that would have been issued upon conversion to reflect the weighted average impact of the number of days the preferred stock was outstanding in 2010. Preferred dividends and other charges totaled $40.3 million in 2012, $40.1 million in 2011 and $51.8 million in 2010.
d.
Amount represents total equivalent common stock shares assuming conversion of 8% preferred stock (Note 9). Preferred dividends and inducement payments totaled $1.0 million in 2012, $2.7 million in 2011 and $14.9 million in 2010.
e.
Amount represents total equivalent common stock shares assuming conversion of 6¾% preferred stock (Note 9). Preferred dividends, amortization of convertible preferred stock issuance costs and inducement payments for the early conversion of preferred stock totaled $9.4 million in 2010.
f.
Amount represents total equivalent common stock shares assuming conversion of 4% convertible notes (Note 7). There was no net interest expense on the 4% convertible notes in 2012 and net interest expense totaled $1.6 million in 2011. The 2010 amount is reduced from the total 12.5 million equivalent shares that would have been issued upon conversion to reflect the weighted average impact of the number of days the debt was outstanding in 2010.
g.
Amount represents total equivalent common stock shares assuming conversion of 5¼% convertible notes (Note 7). There was no net interest expense on the 5¼% convertible notes in 2012 and net interest expense totaled $0.7 million in 2011 and $4.4 million in 2010.
Outstanding stock options excluded from the computation of diluted net income (loss) per share of common stock because their exercise prices were greater than the average market price of McMoRan’s common stock during the periods presented are as follows:
11. DISCONTINUED OPERATIONS
In November 1998, McMoRan acquired Freeport Energy, a business engaged in the purchasing, transporting, terminaling, processing, and marketing of recovered sulphur and the production of oil reserves at Main Pass. Prior to August 31, 2000, Freeport Energy was also engaged in the mining of sulphur. In June 2002, Freeport Energy sold substantially all of its remaining sulphur assets. As discussed in Note 1, all of McMoRan’s sulphur operations and major classes of assets and liabilities are classified as discontinued operations in the accompanying consolidated financial statements. All of McMoRan’s sulphur results are included in the accompanying consolidated statements of operations within the caption “Loss from discontinued operations.”
The table below provides a summary of the discontinued results of operations (in thousands):
Exit From Sulphur Business
In connection with the June 2002 sale of assets, McMoRan also agreed to be responsible for certain related historical environmental obligations and also agreed to indemnify the purchaser from certain potential liabilities with respect to the historical sulphur operations engaged in by Freeport Sulphur and its predecessor and successor companies, including reclamation obligations. In addition, McMoRan assumed, and agreed to indemnify the purchaser from certain potential obligations, including environmental obligations, other than liabilities existing and identified as of the closing of the sale associated with historical oil and gas operations undertaken by the Freeport-McMoRan companies prior to the 1997 merger of Freeport-McMoRan Inc. and IMC Global Inc. Cumulative legal fees and related settlement amounts incurred since 2002 with respect to this indemnification total approximately $1.2 million (Note 15).
Sulphur Reclamation Obligations
McMoRan is currently meeting its financial obligations relating to the future abandonment of its former Main Pass sulphur facilities with BSEE using financial assurances from MOXY. McMoRan and its subsidiaries’ ongoing compliance with applicable BSEE requirements will be subject to meeting certain financial and other criteria.
12. EMPLOYEE BENEFITS
Stock-Based Awards. At December 31, 2012, McMoRan had four stockholder-approved stock incentive plans. Under each plan McMoRan is authorized to issue a fixed amount of stock-based awards, which include stock options, stock appreciation rights, restricted stock, restricted stock units (RSUs) and other stock-based awards that are issuable in or valued by McMoRan common shares. Below is a summary of McMoRan’s stock incentive plans.
Restricted Stock Units. Under McMoRan’s incentive plans, its Board of Directors granted 30,000 RSUs in 2012, 30,000 RSUs in 2011 and 48,500 RSUs in 2010. The RSUs are converted ratably into an equivalent number of shares of McMoRan common stock on the first three anniversaries of the grant date, except for RSUs granted to the non-management directors, which vest incrementally over the first four anniversaries of the grant date. RSUs converted into common stock totaled 29,207 shares in 2012, 21,088 shares in 2011 and 18,596 shares in 2010. Upon issuance of the RSUs, unearned compensation equivalent to the market value at the date of grant is recorded as deferred compensation in stockholders’ equity and is charged to expense over the three or four-year vesting period of each respective grant. McMoRan charged approximately $0.4 million of this deferred compensation to expense in each of the years ending December 31, 2012, 2011 and 2010.
Stock Options. McMoRan’s Board of Directors grants stock options under its stock incentive plans. Except for certain awards described below, the stock options become exercisable in 25 percent annual increments beginning one year from the date of grant and expire ten years after the date of grant. Under the terms of the stock incentive plans all unvested options become fully vested and exercisable upon a change of control with respect to McMoRan’s ownership (Note 2). A summary of stock options outstanding follows:
The total intrinsic value of options exercised during the years ended December 31, 2012, December 31, 2011 and 2010 was $5.2 million, $0.9 million and $2.1 million, respectively. The weighted average fair value per share of shares vested during the years ended December 31, 2012, 2011 and 2010 was $10.97, $11.31 and $11.42, respectively. The total intrinsic value of all McMoRan options outstanding at December 31, 2012 was $17.0 million with a weighted average life of 4.7 years. The total intrinsic value of exercisable options totaled $14.0 million at December 31, 2012. The exercisable options had a weighted average life of 4.1 years and a weighted average exercise price of $14.35.
The Co-Chairmen of McMoRan’s Board of Directors and McMoRan’s Treasurer agreed to forgo all cash compensation during each of the three years ended December 31, 2012. In lieu of cash compensation, McMoRan has granted the Co-Chairmen and Treasurer stock options that are immediately exercisable upon grant and have a term of ten years. These grants to the Co-Chairmen and Treasurer totaled 445,000 options at an exercise price of $13.00 per share in February 2012, 445,000 options at an exercise price of $17.25 per share in February 2011 and 445,000 options at an exercise price of $15.73 per share in February 2010. The Co-Chairmen and Treasurer also received additional grants totaling 380,000 stock options in February 2012, February 2011 and February 2010 (with the same respective periods’ exercise prices stated above), all of which vest ratably over a four-year period.
Compensation cost charged against earnings for stock-based awards is shown below (in thousands):
a.
Includes $4.0 million, $4.9 million and $4.7 million of compensation charges associated with immediately vested stock options granted to certain executive officers (including McMoRan’s Co-Chairmen and Treasurer) during 2012, 2011 and 2010, respectively. Also includes $2.0 million, $2.3 million and $2.0 million of compensation charges related to stock options granted to retirement-eligible employees, which resulted in one-year’s compensation expense being immediately recognized at the date of the stock option grant during 2012, 2011 and 2010, respectively.
A summary of the classification of stock-based compensation by financial statement line item for the three years in the period ended December 31, 2012 is as follows (in thousands):
As of December 31, 2012, total compensation cost related to nonvested, approved stock option awards not yet recognized in earnings was approximately $16.0 million, which is expected to be recognized over a weighted average period of one year. However, should the definitive merger agreement with FCX be finalized (Note 2) certain outstanding stock options will fully vest in accordance with change of control provisions in the respective stock option agreements. Currently with the execution of the merger agreement, certain officers of McMoRan (specifically, the Co-Chairmen of the Board of Directors, Chief Financial Officer and Treasurer) waived their contractual right to accelerated vesting of equity awards as a result of the FCX/MMR merger.
The fair value of option awards is estimated on the date of grant using a Black-Scholes option valuation model. Expected volatility is based on implied volatilities from the historical volatility of McMoRan’s stock, and to a lesser extent, on traded options on McMoRan’s common stock. McMoRan uses historical data to estimate option exercise, forfeitures and expected life of the options. The risk-free interest rate is based on Federal Reserve rates in effect for bonds with maturity dates equal to the expected term of the option at the date of grant. McMoRan has not paid, and is currently not permitted to pay, cash dividends on its common stock. The weighted average fair value of stock options granted and assumptions used to value stock option awards during the years ended December 31, 2012, 2011 and 2010 are noted in the following table:
a.
Excludes stock options that were granted with immediate vesting (445,000 shares, including 400,000 shares granted to the Co-Chairmen in lieu of cash compensation for 2012, 2011 and 2010). The expected life and fair value of stock options on the respective grant dates during the years ended December 31, 2012, 2011 and 2010 for such option awards are as follows:
On January 28, 2013, McMoRan’s Board of Directors granted a total of 928,000 stock options to its employees at an exercise price of $15.91 per share, which vest ratably over a four-year period.
Other Benefits. McMoRan provides certain health care and life insurance benefits (Other Benefits) to retired employees. McMoRan has the right to modify or terminate these benefits. For the year ended December 31, 2012, the health care trend rate used for Other Benefits was 8.0 percent in 2012, decreasing ratably annually until reaching 4.5 percent in 2029. For the year ended December 31, 2011, the health care trend rate used for Other Benefits was 7.9 percent in 2011, decreasing ratably annually until reaching 4.5 percent in 2028. A one-percentage-point increase or decrease in assumed health care cost trend rates would not have a significant impact on service or interest costs. Information on the Other Benefits plan follows (in thousands):
Expected benefit payments for the Other Benefits plan approximate $0.4 million in each of the three years ending December 31, 2015, $0.3 million in the years ending December 31, 2016 and 2017 and a total of $1.2 million during the five years thereafter. The components of net periodic benefit cost for McMoRan’s plans follow (in thousands):
Included in accumulated other comprehensive loss at December 31, 2012, are prior service costs of $0.1 million that have not been recognized in net periodic benefit costs associated with the Other Benefits. The total amount expected to be recognized into net periodic costs in 2013 associated with these prior service credits and actuarial gains and losses is immaterial.
McMoRan has an employee savings plan under Section 401(k) of the Internal Revenue Code. The plan allows eligible employees to contribute up to 75 percent of their pre-tax compensation, subject to certain limits prescribed by the Internal Revenue Code. McMoRan matches 100 percent of each employees’ contribution up to a maximum of 5 percent of each employees’ annual basic compensation amount. In this plan, participants exercise control and direct the investment of their contributions and account balances among various investment options. In connection with the termination of its defined benefits plan, McMoRan enhanced the savings plan for substantially all its employees. Pursuant to the enhancements, McMoRan contributes amounts to individual employee accounts totaling either 4 percent or 10 percent of each employee’s pay, depending on a combination of each employee’s age and years of service with McMoRan. Participants who were actively employed on January 1, 2009 became fully
vested in the matching contributions. Plan participants vest in McMoRan’s enhanced contributions upon completing three years of service with McMoRan. For employees whose eligible compensation exceeds certain levels, McMoRan provides an unfunded defined contribution plan. The balance of this liability totaled $0.6 million on December 31, 2012 and $1.1 million on December 31, 2011.
McMoRan’s results of operations reflect charges to expense totaling $1.0 million in 2012, $1.0 million in 2011 and $1.1 million in 2010 for its aggregate matching contributions for the Section 401(k) savings plan and the defined contribution plan. Additionally, McMoRan has other employee benefit plans, certain of which are related to McMoRan’s performance, which costs are recognized currently in general and administrative expense.
McMoRan also has a contractual obligation to reimburse a third party for a portion of its postretirement benefit costs relating to certain former retired sulphur employees (Note 15).
13. INCOME TAXES
McMoRan has a net deferred tax asset of $494.7 million as of December 31, 2012, resulting from net operating loss carryforwards and other temporary differences related to McMoRan’s activities. McMoRan has provided a valuation allowance, including approximately $42.4 million associated with McMoRan’s discontinued sulphur operations, for the full amount of these net deferred tax assets. McMoRan’s effective tax rate would be impacted in future periods to the extent these deferred tax assets are recognized. McMoRan will continue to assess whether or not its deferred tax assets can be recognized based on operating results in future periods. McMoRan has no material uncertain tax positions as of December 31, 2012.
As of December 31, 2012 and 2011, McMoRan had federal tax net operating loss carryforwards (NOLs) of approximately $952.9 million and $733.9 million, respectively, and state tax NOLs of approximately $341.8 million and $300.5 million, respectively. These NOLs are scheduled to expire in varying amounts between tax years 2013 through 2032.
Federal tax regulations impose certain annual limitations on the utilization of NOLs from prior periods when a defined level of change in the stock ownership of certain stockholders is exceeded. If a corporation has a statutorily defined change of ownership, its ability to use its existing NOLs could be limited by Section 382 of the Internal Revenue Code depending upon the level of future taxable income generated in a given year and other factors. McMoRan determined that such a change of ownership occurred during 2010, which, depending upon the amounts and timing of future taxable income generated, may limit McMoRan’s ability to use its existing NOLs to fully offset taxable income in individual future periods.
Interest or penalties associated with income taxes are recorded as components of the provision for income taxes, although no such amounts have been recognized in the accompanying financial statements. Currently, McMoRan’s major taxing jurisdictions are the United States (federal) and Louisiana. Tax periods open to audit for McMoRan primarily include federal and Louisiana income tax returns subsequent to 2008. NOLs amounts prior to this time are also subject to audit.
The components of McMoRan’s deferred tax assets (liabilities) at December 31, 2012 and 2011 follow (in thousands):
Reconciliations of the differences between income taxes computed at the federal statutory tax rate and the income taxes recorded follow (in thousands):
14. TRANSACTIONS WITH AFFILIATES
FM Services Company, a wholly owned subsidiary of FCX and a company with which McMoRan shares certain common executive management, provides McMoRan with certain administrative, financial and other services on a contractual basis. These service costs, which include related overhead amounts, including rent for the New Orleans, Louisiana corporate headquarters, totaled $7.7 million in 2012, $7.9 million in 2011 and $7.7 million in 2010. Management believes these costs do not differ materially from the costs that would have been incurred had the relevant personnel providing the services been employed directly by McMoRan. At each of December 31, 2012 and 2011, McMoRan had an obligation to fund $2.9 million of FM Services costs, primarily reflecting long-term employee pension and postretirement medical obligations (Notes 6 and 12).
On December 30, 2010, FCX purchased 500,000 shares of McMoRan’s 5.75% preferred stock (Note 9).
On December 5, 2012, McMoRan signed a definitive merger agreement under which FCX will acquire McMoRan for approximately $3.4 billion in cash, or $2.1 billion net of the 36 percent McMoRan ownership interest currently held by FCX and PXP (Note 2).
15. COMMITMENTS AND CONTINGENCIES
Oil and Gas Operations. McMoRan has $118.9 million of estimated commitments related to its planned oil and gas exploration and development activities, including costs related to projects currently in progress, inventory purchase commitments and other exploration expenditures. Included in this amount is $16.0 million of expenditures for drilling rig contract charges anticipated to be expended over the next year which McMoRan expects to share with its partners in its exploration program.
Long-Term Contracts and Operating Leases. McMoRan’s primary operating leases involve renting office space in two buildings in Houston, Texas, which expire in April 2014 and July 2014, and office space in Lafayette, Louisiana, which expires in November 2015. At December 31, 2012, McMoRan’s total minimum annual contractual charges aggregated $4.1 million, with payments totaling $2.5 million in 2013, $1.5 million in 2014 and $0.1 million in 2015. Rent expense, including rent allocated to McMoRan by FM Services (Note 14), totaled $3.0 million in each of the years in the three year period ended December 31, 2012.
Other Liabilities. Freeport Energy has a contractual obligation to reimburse a third party a portion of its postretirement benefit costs relating to certain retired former sulphur employees of Freeport Energy. This contractual obligation totaled $1.8 million at December 31, 2012 and $1.5 million at December 31, 2011, including $0.5 million and $0.7 million in current liabilities from discontinued operations, respectively. A third-party actuarial consultant assesses the estimated related future costs associated with this contractual liability on an annual basis using current health care trend costs and incorporating changes made to the underlying benefit plans of the third party. The assessment at year end 2012 used an initial health care cost trend rate of 8.0 percent in 2012 decreasing ratably to 4.5 percent in 2029. The assessment at year end 2011 used an initial health care cost trend rate of 7.9 percent in 2011 decreasing
ratably to 4.5 percent in 2028. McMoRan applied a discount rate of 8.5 percent at December 31, 2012 and 2011 to the consultant’s future cost estimates. McMoRan increased the liability by $0.8 million at December 31, 2012 primarily due to estimated increases in future health claim costs resulting from higher than expected actual health claim reimbursements and higher health trend costs. McMoRan reduced the liability by $1.6 million at December 31, 2011, due to lower than expected actual health claim reimbursements at that time, partially offset by higher health trend costs. Future revisions to this estimate resulting from changes in assumptions or actual results varying from projected results will be recorded in earnings.
Environmental and Reclamation. McMoRan has made, and will continue to make, expenditures for the protection of the environment. McMoRan is subject to contingencies as a result of environmental laws and regulations. Present and future environmental laws and regulations applicable to McMoRan’s operations could require substantial capital expenditures or could adversely affect its operations in other ways that cannot be predicted at this time. Cumulative legal fees and related settlement amounts incurred with respect to historical oil and gas liabilities McMoRan assumed from IMC Global since 2002 total approximately $1.2 million. No additional amounts have been recorded because no specific liability requiring McMoRan to fund any material future amounts has been identified and assessed to be probable.
Since 2007 McMoRan has funded over $430 million of reclamation costs to settle a significant portion of the asset retirement obligations assumed in an oil and gas property acquisition in 2007, including certain properties damaged in the 2008 hurricanes. McMoRan’s estimates of existing asset retirement obligations involve inherent uncertainties and are subject to change over time as a result of several factors, including, without limitation, changes in the industry’s regulatory environment, changes in the cost and availability of required equipment and expertise to complete the work, changes in timing, and changes in scope that are identified as reclamation projects progress. McMoRan revises its reclamation estimates, as appropriate, when such changes in estimates become known.
The results from these reclamation activities as well as information obtained from other industry sources indicate that the cost to conduct reclamation projects in the offshore Gulf of Mexico region has risen in recent years, particularly since the occurrence of the 2010 Deepwater Horizon incident. As a result, McMoRan re-assessed the estimates of substantially all of its oil and gas property asset retirement obligations in 2011. As a result of this assessment McMoRan revised its estimates related to certain, ongoing and/or near term reclamation projects resulting in an increase to accretion expense of approximately $57.3 million in 2011. Approximately $19.8 million of these charges were reimbursed to McMoRan under its insurance policies related to damage restoration costs resulting from the 2008 hurricane events. In addition, McMoRan also revised its estimates related to certain longer term producing properties resulting in adjustments that increased property, plant and equipment by approximately $54.6 million in 2011.
For year ended December 31, 2012 McMoRan recorded approximately $17.6 million to accretion expense related to certain ongoing reclamation projects and approximately $7.7 million of adjustments for certain longer term producing properties, the impact of which increased property, plant and equipment.
Revisions made for certain properties depending upon the respective circumstances include consideration of the following: (1) the inclusion of estimates for new properties; (2) changes in the projected timing of certain reclamation costs because of changes in the estimated timing of the depletion of the related proved reserves for McMoRan’s oil and gas properties and new estimates for the timing of the reclamation for the structures comprising the MPEHtm project and former sulphur facilities at Main Pass; (3) changes in the reclamation costs based on revised estimates of future reclamation work to be performed; and (4) when applicable, changes in McMoRan’s credit-adjusted, risk-free interest rate. McMoRan’s credit adjusted, risk-free interest rates ranged from 4.2 percent to 8.2 percent at December 31, 2012, 4.1 percent to 6.4 percent at December 31, 2011 and 4.6 percent to 9.9 percent at December 31, 2010. At December 31, 2012, McMoRan’s estimated undiscounted reclamation obligations, including inflation and market risk premiums, totaled $369.4 million, including $41.4 million associated with its remaining sulphur obligations. A rollforward of McMoRan’s consolidated discounted asset retirement obligations (including both current and long term liabilities) follows (in thousands):
a.
Accretion expense and other charges to operations are included within depletion, depreciation and amortization expense in the accompanying consolidated statements of operations.
b.
Included within loss from discontinued operations.
At December 31, 2012, McMoRan had $4.9 million in restricted investments associated with third party prepayments of their share of future abandonment costs and $56.4 million held in escrow associated with surety funding requirements in favor of a third party related to a portion of the reclamation obligations assumed in a 2007 oil and gas property acquisition. McMoRan is required to make quarterly installment payments under this arrangement totaling $5.0 million per year until certain requirements under the arrangement are met. These restricted funds are classified as long-term restricted cash in the accompanying consolidated balance sheets.
Litigation. McMoRan may from time to time be involved in various legal proceedings of a character normally incident to the ordinary course of its business. Management believes that potential liability from any of these pending or threatened proceedings will not have a material adverse effect on McMoRan’s financial condition or results of operations.
Between December 11, 2012 and December 26, 2012, ten putative class actions challenging the FCX/MMR merger were filed on behalf of all McMoRan stockholders by purported McMoRan stockholders. Nine were filed in the Court of Chancery of the State of Delaware (the “Court of Chancery”). On January 25, 2013, the Court of Chancery consolidated the actions into a single action, In re McMoRan Exploration Co. Stockholder Litigation, No. 8132-VCN. One action was also filed on December 19, 2012 in the Civil District Court for the Parish of Orleans of the State of Louisiana, Langley v. Moffett et al., No. 2012-11904. The defendants in these lawsuits include McMoRan, members of the McMoRan board of directors, FCX, INAVN Corp., a wholly-owned subsidiary of FCX (the “merger sub”), another subsidiary of FCX, the Gulf Coast Ultra Deep Royalty Trust and PXP. The lawsuits allege, among other things, that members of the McMoRan board of directors breached their fiduciary duties to McMoRan’s stockholders because they, among other things, pursued their own interests at the expense of stockholders and failed to maximize stockholder value with respect to the merger, and that FCX, the merger sub and PXP aided and abetted that breach of fiduciary duties. The consolidated Delaware action also asserts claims derivatively on behalf of McMoRan. These lawsuits seek, among other things, an injunction barring or rescinding the FCX/MMR merger, damages, and attorney’s fees and costs.
In addition, between December 14, 2012 and January 16, 2013, thirteen derivative actions challenging the FCX/MMR merger and/or the FCX/PXP merger were filed on behalf of FCX by purported
FCX stockholders. Ten were filed in the Court of Chancery of the state of Delaware and three were filed in the Superior Court of the State of Arizona, County of Maricopa (the “Arizona Superior Court”). On January 25, 2013, the Court of Chancery consolidated the Delaware actions into a single action, In re Freeport-McMoRan Copper & Gold, Inc. Derivative Litigation, No. 8145-VCN. On January 17, 2013, the Arizona Superior Court consolidated two of the Arizona actions into In re Freeport-McMoRan Derivative Litigation, No. CV2012-018351. A third Arizona complaint, Harris v. Adkerson et al., No. CV2013-004163, filed on January 16, 2013, has not yet been consolidated. The defendants in these lawsuits include directors and certain officers of FCX, two FCX subsidiaries, McMoRan and certain of McMoRan’s directors and officers, and PXP and certain of PXP’s directors. These lawsuits allege, among other things, that the FCX directors breached their fiduciary duties to FCX’s stockholders because they, among other things, pursued their own interests at the expense of stockholders in approving the FCX/MMR merger and the FCX/PXP merger. These lawsuits further allege that the other defendants aided and abetted that breach of fiduciary duties. These lawsuits seek, among other things, an injunction barring or rescinding both the FCX/MMR merger and the FCX/PXP merger and requiring submission of both the FCX/MMR merger and the FCX/PXP merger to a vote of FCX stockholders, damages, and attorneys’ fees and costs. The McMoRan and FCX defendants believe the lawsuits are without merit and intend to defend vigorously against them.
16. MAIN PASS ENERGY HUBTM PROJECT
McMoRan’s long-term business objective of the Main Pass Energy HubTM (MPEHTM) is to maximize the value of the offshore structures used in its former sulphur operations located at Main Pass in the Gulf of Mexico, 38 miles east of Venice, Louisiana. Currently McMoRan’s subsidiary, Freeport-McMoRan Energy LLC, and a third party are engaged in efforts to utilize the MPEH™ as a potential deepwater port facility/terminal to receive, store, condition and liquefy domestic natural gas for export as LNG. Natural gas would be received by a pipeline at MPEHTM ,processed and then transferred to on-site floating liquefaction storage and offloading vessels for liquefaction and offloading to LNG transport vessels for export to foreign locations. MPEH™ is located close to significant Gulf Coast natural gas production and numerous interstate pipelines and offshore gathering systems. The project would utilize existing offshore structures of the MPEH™, which was approved by the U.S. Maritime Administration in 2007 as a deepwater port for the importation and regasification of LNG, conditioning of natural gas to produce NGLs, and storage of natural gas in salt caverns. Modification of the Main Pass facilities to accommodate use as an LNG export facility would require additional permit approvals.
On January 4, 2013, the Department of Energy authorized MPEH™ to export domestically produced LNG by vessel from the proposed MPEH™ to any country that has or subsequently enters into a free trade agreement (FTA) with the United States. The approval allows export of up to 24 million tonnes of LNG per annum (3.2 Bcf per day) for a 30-year term, beginning on the earlier of the date of first export or 8 years from the date the authorization is issued (January 4, 2021), pursuant to one or more long-term contracts with third parties that do not exceed the term of this authorization. A non-FTA application, seeking approval to export to countries without free trade agreements with the United States, is being developed.
McMoRan is engaged in studies to define the project and related permitting requirements and is developing commercial arrangements required to support the significant capital investments involved in the MPEH™ project. The ultimate outcome of its efforts to enter into commercial arrangements on reasonable terms to develop the MPEH™ project and obtain additional financing to fund the MPEH™ project is subject to various uncertainties, many of which are beyond McMoRan’s control.
The costs associated with the establishment of the MPEH™ project have been charged to expense in the accompanying consolidated statements of operations. These costs will continue to be charged to expense until commercial feasibility is established. McMoRan incurred costs for the MPEH™ project totaling $0.3 million in 2012, $0.6 million in 2011 and $1.0 million in 2010.
17. SUPPLEMENTARY OIL AND GAS INFORMATION
McMoRan’s oil and gas exploration, development and production activities are primarily conducted offshore in the Gulf of Mexico and onshore in the Gulf Coast region of the United States. Supplementary information presented below is prepared in accordance with requirements prescribed by U.S. generally accepted accounting principles.
Oil and Gas Capitalized Costs.
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities.
The following table reflects the net changes in McMoRan’s capitalized exploratory well drilling costs during each of the three years in the period ended December 31, 2012 (in thousands):
McMoRan has investments in drilling and capitalized prospect and other costs for in-progress and/or unproven exploratory wells totaling $1,134.7 million at December 31, 2012. In addition, McMoRan’s allocated costs for the working interests acquired in properties associated with McMoRan’s current in-progress and unproven wells totaled $693.5 million at December 31, 2012.
As of December 31, 2012, McMoRan had four wells (the Davy Jones initial discovery well - “Davy Jones No. 1”, the Davy Jones offset appraisal well - “Davy Jones No. 2”, Blackbeard West No. 1 and Hurricane Deep) with costs that have been capitalized for a period in excess of one year following the completion of initial exploratory drilling operations.
In 2010, the Davy Jones No. 1 well logged 200 net feet of pay in multiple Wilcox sands, which were all full to base. Davy Jones No. 2, which is located two and a half miles southwest of Davy Jones No. 1, confirmed 120 net feet of pay in multiple Wilcox sands and also encountered 192 net feet of potential hydrocarbons in the Tuscaloosa and Lower Cretaceous carbonate sections. McMoRan is the operator and holds a 63.4 percent working interest and a 50.2 percent net revenue interest in Davy Jones.
Davy Jones No. 1 completion activities initiated in the fourth quarter of 2011 and initial flow testing procedures were attempted in March 2012, however McMoRan encountered mechanical issues with the well’s originally designed perforating equipment. Subsequent activities to flow test the well were conducted in 2012, and additional procedures to achieve a measurable flow rate are required. Future plans will incorporate data gained to date at Davy Jones as well as potential core and log data from the in-progress well at Lineham Creek, located onshore approximately 50 miles northwest of Davy Jones. The rig has been moved off location for several months while a large-scale hydraulic fracture treatment is designed to penetrate the Wilcox reservoirs to facilitate hydrocarbon movement into the wellbore. McMoRan’s investment in well drilling, completion and other costs specifically attributable to Davy Jones No. 1 approximated $318.4 million as of December 31, 2012.
Completion and testing of the Davy Jones offset appraisal well (Davy Jones No. 2) is expected to commence following review of results from Davy Jones No. 1. Davy Jones is located on a 20,000 acre structure that has multiple additional drilling opportunities.
McMoRan’s total investment in the Davy Jones complex, which includes $474.8 million in allocated property acquisition costs, totaled $1,024.0 million at December 31, 2012.
The Blackbeard West No. 1 ultra-deep exploration well on South Timbalier Block 168 was drilled to a total depth of 32,997 feet in October 2008 and logs below 30,067 feet indicated potential hydrocarbon bearing zones measuring 220 net feet requiring further evaluation. The well has been temporarily abandoned while McMoRan evaluates whether to drill deeper or complete the well to test the existing zones. McMoRan’s lease rights to the Blackbeard West Unit (including Blackbeard West No. 1) are currently held by activities associated with Blackbeard West No. 2 (discussed below) while McMoRan’s evaluation of Blackbeard West No. 1 continues. McMoRan’s investment in the Blackbeard West No. 1 drilling costs approximated $31.1 million at December 31, 2012.
The Blackbeard West No. 2 ultra-deep exploration well on Ship Shoal Block 188 was drilled to a total depth of 25,584 feet in January 2013. Through logs and core data, McMoRan has identified three potential hydrocarbon bearing Miocene sand sections between approximately 20,800 and 24,000 feet. McMoRan holds a 69.4 percent working interest and a 53.1 percent net revenue interest in Ship Shoal Block 188. McMoRan’s investment in Blackbeard West No. 2 totaled $90.6 million at December 31, 2012. In addition, McMoRan has approximately $27.6 million of allocated property acquisition costs for the Blackbeard West unit.
The Hurricane Deep well, on South Marsh Island Block 217, was drilled to a true vertical depth of 21,378 feet in July 2011. Log results indicated the presence of Operc and Gyro sands that McMoRan determined could be pursued in an updip location. The well was temporarily abandoned to preserve the wellbore while McMoRan evaluates opportunities to sidetrack or deepen the well. McMoRan’s total investment in Hurricane Deep, which includes $24.8 million in allocated property acquisition costs, totaled $55.5 million at December 31, 2012.
The Blackbeard East ultra-deep exploration by-pass well, which is located on South Timbalier Block 144 in 80 feet of water, was drilled to a total depth of 33,318 feet in January 2012. Exploration results from the well indicate the presence of hydrocarbons below the salt weld in geologic formations including Upper/Middle Miocene, Frio, Vicksburg, and Sparta carbonate. Pressure and temperature data below the salt weld in the Miocene sands between 19,500 feet and 24,600 feet at Blackbeard East indicate that a completion at these depths could utilize conventional equipment and technologies. McMoRan’s lease rights to South Timbalier Block 144 were scheduled to expire on August 17, 2012. Prior to the expiration, McMoRan submitted initial development plans for Blackbeard East to the Bureau of Safety and Environmental Enforcement of the United States Department of the Interior (BSEE). McMoRan is seeking approval to test and complete the middle Miocene sands during 2013 using conventional equipment and technologies. Additional plans for further development of the deeper zones continue to be evaluated. McMoRan continues to hold its rights to this lease while its development plans are under administrative consideration by BSEE. McMoRan’s ability to continue to preserve its interest in Blackbeard East will require approval from the BSEE of its development plans.
McMoRan holds a 72.0 percent working interest and a 57.4 percent net revenue interest in Blackbeard East. McMoRan’s total investment in Blackbeard East, which includes $130.5 million in allocated property acquisition costs, totaled $308.8 million at December 31, 2012.
The Lafitte ultra-deep exploration well, which is located on Eugene Island Block 223 in 140 feet of water, was drilled to a total depth of 34,162 feet in March 2012. Exploration results from the well indicate the presence of hydrocarbons below the salt weld in geologic formations including Middle/Lower Miocene, Frio, Upper Eocene, and Sparta carbonate. McMoRan’s lease rights to Eugene Island Block 223 were scheduled to expire on October 8, 2012. Prior to the lease expiration, McMoRan submitted its initial development plans to complete and test the Jackson/Yegua sands in the upper Eocene for Lafitte to the BSEE. McMoRan continues to hold its rights to this lease while its development plans are under administrative consideration by the BSEE. McMoRan’s ability to continue to preserve its interest in Lafitte will require approval from the BSEE of its development plans.
McMoRan holds a 72.0 percent working interest and a 58.3 percent net revenue interest in Lafitte. McMoRan’s total investment in Lafitte, which includes $35.8 million in allocated property acquisition costs, totaled $196.8 million at December 31, 2012.
Proved Oil and Natural Gas Reserves (Unaudited). Proved oil and natural gas reserves for the periods ending December 31, 2012, 2011 and 2010 have been estimated by Ryder Scott Company, L.P. (Ryder Scott), in accordance with the guidelines established by the Security and Exchange Commission (SEC) as set forth in Rule 4-10 (a) (6), (22), (26) and (31). All estimates of oil and natural gas reserves are inherently imprecise and subject to change as new technical information about the properties is obtained. Estimates of proved reserves for wells with little or no production history are less reliable than those based on a long production history. Subsequent evaluation of the same reserves may result in variations which may be substantial. Revisions of proved reserves represent changes in previous estimates of proved reserves resulting from new information obtained from production history, additional development drilling and/or changes in other factors, including economic considerations. Discoveries and extensions represent additions to proved reserves resulting from (1) extensions of proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to initial discovery, and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Substantially all of McMoRan's proved reserves are located offshore in the Gulf of Mexico. Oil and natural gas liquids (NGLs), are stated in thousands of barrels (MBbls) and natural gas in millions of cubic feet (MMcf).
a.
Reflects the estimated proved reserves associated with the 2010 oil and gas property acquisition (Note 3).
b.
Includes 12,203 MMcf of natural gas and 122 MBbls of oil associated with the Lineham Creek onshore ultra-deep exploratory well.
c.
Reflects the estimated proved reserves associated with the 2012 oil and gas property sales (Note 3).
d.
At December 31, 2012, McMoRan had natural gas imbalances of 0.5 Bcfe for under deliveries and 0.5 Bcfe for over deliveries which are not reflected in the above reserve quantities.
e.
Includes 9,165 MMcf of natural gas, 107 MBbls of oil and 11 MBbls of NGLs associated with properties sold in January 2013 (Note 3)
Standardized Measure of Discounted Future Net Cash Flows From Proved Oil and Natural Gas Reserves (Unaudited).
McMoRan’s standardized measure of discounted future net cash flows (Standardized Measure) and changes therein relating to proved oil and natural gas reserves were computed using reserve valuations based on regulations and parameters prescribed by the SEC. SEC regulations require the use of average prices during the 12-month period prior to the reporting date. The weighted average of these prices for all properties with proved reserves was $106.68 per barrel of oil, $46.56 per barrel of NGLs and $2.84 per Mcf of natural gas at December 31, 2012 and was $100.68 per barrel of oil, $56.82 per barrel of NGLs and $4.29 per Mcf of natural gas at December 31, 2011.
a.
For both of the years ended December 31, 2012 and 2011 McMoRan’s available tax benefits directly related to its oil and gas operations exceeded its pretax future net cash flows under the Standardized Measure.
b.
Amount reflects application of required 10 percent discount rate to both the estimated future income taxes and estimated future net cash flows associated with production of the estimated proved reserves.
c.
Includes $16.1 million associated with properties sold in January 2013 (Note 3).
Changes in Standardized Measure of Discounted Future Net Cash Flows From Proved Oil and Natural Gas Reserves (Unaudited).
a. Reflects sale of certain oil and gas properties during 2012 (Note 3).
18. GUARANTOR FINANCIAL STATEMENTS
In November 2007, McMoRan completed the sale of $300 million of 11.875% notes (Note 7). The 11.875% notes are unconditionally guaranteed on a senior basis jointly and severally by MOXY and the subsidiary guarantors. The guarantee is an unsecured obligation of the guarantor and ranks equal in right of payment with all existing and future indebtedness of McMoRan, including indebtedness under the credit facility. The guarantee also ranks senior in right of payment with all future subordinated obligations and is effectively subordinated in right of payment to any debt of McMoRan’s subsidiaries that are not subsidiary guarantors.
The following condensed consolidating financial information includes information regarding McMoRan, as parent, MOXY and its subsidiaries, as guarantors, and Freeport Energy, as the
non-guarantor subsidiary. Included are the condensed consolidating balance sheets at December 31, 2012 and 2011 and the related condensed consolidating statements of operations and cash flow for the years ended December 31, 2012, 2011 and 2010, which should be read in conjunction with the notes to these consolidated financial statements:
CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2012
CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2011
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
Year Ended December 31, 2012
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
Year Ended December 31, 2011
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
Year Ended December 31, 2010
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOW
Year Ended December 31, 2012
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOW
Year Ended December 31, 2011
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOW
Year Ended December 31, 2010
19. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
a.
Represents net income (loss) attributable to common stockholders, which includes preferred dividends and inducement payments for early conversion of preferred stock as a reduction to net income (loss).
b.
Includes approximately $39.7 million in gains from sales of oil and gas properties.
c.
Incudes approximately $39.1 million in insurance recoveries associated with prior hurricane damage related claims.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not Applicable.
Item 9A.
Item 9A. Controls and Procedures
(a) Evaluation of disclosure controls and procedures. Our chief executive officer and chief financial officer, with the participation of management, have evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this annual report on Form 10-K. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective as of the end of the period covered by this report.
(b) Management’s Report on Internal Control over Financial Reporting and Report of Independent Registered Public Accounting Firm. The information required to be furnished pursuant to this item is set forth under the captions “Management’s Report on Internal Control over Financial Reporting” and “Report of Independent Registered Public Accounting Firm” in Item 8. of this report.
(c) Changes in internal controls. There has been no change in our internal control over financial reporting that occurred during the quarter ended December 31, 2012 that has materially affected, or is 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
The information required by Item 10 regarding our executive officers appears in a separately captioned heading after Item 4. in Part I of this report on Form 10-K. The information set forth under the headings “Information About Director Nominees,” “Section 16(a) Beneficial Ownership Reporting Compliance,” “Corporate Governance - Corporate Guidelines; Ethics and Business Conduct Policy,” “Corporate Governance - Board Committees” and “Corporate Governance - Board and Committee Independence and Audit Committee Financial Experts” of our definitive proxy statement to be filed with the Securities and Exchange Commission (SEC) pursuant to Regulation 14A, relating to our 2013 annual meeting of stockholders is incorporated herein by reference or, in the event we do not prepare and file such proxy statement, such information shall be filed as an amendment to this Form 10-K. Such information shall be filed no later than April 30, 2013.
Item 11.
Item 11. Executive Compensation
The information set forth under the headings “Director Compensation” and “Executive Officer Compensation” of our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A, relating to our 2013 annual meeting of stockholders is incorporated herein by reference or, in the event we do not prepare and file such proxy statement, such information shall be filed as an amendment to this Form 10-K. Such information shall be filed no later than April 30, 2013.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters
The information set forth under the headings “Stock Ownership of Directors and Executive Officers” and “Stock Ownership of Certain Beneficial Owners” of our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A, relating to our 2013 annual meeting of stockholders is incorporated herein by reference or, in the event we do not prepare and file such proxy statement, such information shall be filed as an amendment to this Form 10-K. Such information shall be filed no later than April 30, 2013.
Securities Authorized for Issuance Under Equity Compensation Plans.
The following table provides information as of December 31, 2012, with respect to compensation plans under which our equity securities are authorized for issuance.
Finally, there were also 1,000 shares remaining available for future issuance to our non-management directors and advisory directors under the 2004 Director Compensation Plan.
See Note 12 to our consolidated financial statements for further information regarding the significant features of the above plans.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information set forth under the heading “Certain Transactions” of our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A, relating to our 2013 annual meeting of stockholders is incorporated herein by reference or, in the event we do not prepare and file such proxy statement, such information shall be filed as an amendment to this Form 10-K. Such information shall be filed no later than April 30, 2013.
Item 14.
Item 14. Principal Accounting Fees and Services
The information set forth under the heading “Independent Registered Public Accounting Firm” of our definitive proxy statement to be filed pursuant to Regulation 14A, relating to our 2013 annual meeting of stockholders is incorporated herein by reference or, in the event we do not prepare and file such proxy statement, such information shall be filed as an amendment to this Form 10-K. Such information shall be filed no later than April 30, 2013.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a)(1). Financial Statements. Reference is made to Item 8 hereof.
(a)(2).
Financial Statement Schedules. All financial statement schedules are either not required under the related instructions or are not applicable because the information has been included elsewhere herein.
(a)(3).
Exhibits. Reference is made to the Exhibit Index beginning on page E-1 hereof.
____________________
GLOSSARY
3-D seismic data. Seismic data which has been digitally recorded, processed and analyzed in a manner that permits color enhanced three-dimensional displays of geologic structures. Seismic data processed in that manner facilitates more comprehensive and accurate analysis of subsurface geology, including the potential presence of hydrocarbons.
Bbl or Barrel. One stock tank barrel, or 42 U.S. gallons liquid volume (used in reference to crude oil or other liquid hydrocarbons).
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.
Block. A block depicted on the Outer Continental Shelf Leasing and Official Protraction Diagrams issued by BOEM (defined below) or a similar depiction on official protraction or similar diagrams issued by a state bordering on the Gulf of Mexico.
Blowouts. Accidents resulting from penetration of a gas or oil reservoir during drilling operations under higher-than-calculated pressure.
BOEM. The Bureau of Ocean Energy Management (an agency of the Department of the Interior; formed upon dissolution of the Bureau of Ocean Energy Management, Regulation and Enforcement October 1, 2011, and responsible for pre-leasing environmental and leasing matters).
BSEE. The Bureau Safety and Environmental Enforcement (an agency of the Department of the Interior; formed upon dissolution of the Bureau of Ocean Energy Management, Regulation and Enforcement October 1, 2011, and responsible for environmental matters related to operations, safety and operational matters generally).
Completion. The installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
Cratering. The collapse of the circulation system dug around the drilling rig for the prevention of blowouts.
Delineation drilling. Drilling a well at a distance from a development well to determine physical extent, reserves and likely production rate of a new oil or gas reservoir.
Developed acreage. Acreage in which there are one or more producing wells or shut-in wells capable of commercial production and/or acreage with established reserves in quantities we deemed sufficient to develop.
Development well. A well drilled into a proved natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.
Farm-in or farm-out. An agreement under which the owner of a working interest in a natural gas and oil lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells at its expense in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The agreement is a “farm-in” to the assignee and a “farm-out” to the assignor.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest and/or operating right is owned.
Gross interval. The measurement of the vertical thickness of the producing and non-producing zones of an oil and gas reservoir.
Gulf of Mexico shelf. The offshore area within the Gulf of Mexico seaward on the coastline extending out to 200 meters water depth.
LNG. Liquefied natural gas.
MBbls. One thousand barrels, typically used to measure the volume of crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet, typically used to measure the volume of natural gas.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
MMBbls. One million barrels, typically used to measure the volume of crude oil or other liquid hydrocarbons.
MMbtu. One million British thermal units.
MMcf. One million cubic feet, typically used to measure the volume of natural gas at specified temperature and pressure.
MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
MMcfe/d. One million cubic feet equivalent per day.
Net acres or net wells. Gross acres or gross wells multiplied by the percentage working interest and/or operating right owned.
Natural gas liquids (NGLs). Hydrocarbons (primarily ethane, propane, butane and natural gasolines) which have been extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature.
Net feet of hydrocarbon bearing sands. The vertical thickness of the producing zone of an oil and gas reservoir.
Net feet of pay. The thickness of reservoir rock estimated to both contain hydrocarbons and be capable of contributing to producing rates.
Net profit interest. An interest in profits realized through the sale of production, after costs. It is carved out of the working interest.
Net revenue interest. An interest in a revenue stream net of all other interests burdening that stream, such as a lessor’s royalty and any overriding royalties. For example, if a lessor executes a lease with a one-eighth royalty, the lessor’s net revenue interest is 12.5 percent and the lessee’s net revenue interest is 87.5 percent.
Non-productive well. A well found to be incapable of producing hydrocarbons in quantities sufficient such that proceeds from the sale of production would exceed production expenses and taxes.
Overriding royalty interest. A revenue interest, created out of a working interest, that entitles its owner to a share of revenues, free of any operating or production costs. An overriding royalty is often retained by a lessee assigning an oil and gas lease.
Pay. Reservoir rock containing oil or gas.
Possible reserves. Reserves that are less certain to be recovered than probable reserves.
Probable reserves. Reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
Productive well. A well that is found to be capable of producing hydrocarbons in quantities sufficient such that proceeds from the sale of production exceed production expenses and taxes.
Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved developed non-producing reserves. Reserves expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production.
Proved developed producing reserves. Reserves expected to be recovered from completion intervals which are open and producing at the time the estimate is made.
Proved developed reserves. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved developed shut-in reserves. Reserves expected to be recovered from (1) completion intervals which are open at the time of the estimate, but which have not stared producing, (2) wells which were shut-in awaiting pipeline connections or as a result of a market interruption or (3) wells not capable of production for mechanical reasons.
Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
Recompletion. An operation whereby a completion in one zone in a well is abandoned in order to attempt a completion in a different zone within the existing wellbore.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Sands. Sandstone or other sedimentary rocks.
SEC. Securities and Exchange Commission.
Sour. High sulphur content.
True Vertical Depth (TVD). The vertical distance from the surface to the current drilling depth.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether the acreage contains proved reserves.
Working interest. The lessee’s interest created by the execution of an oil and gas lease that gives the lessee the right to exploit the minerals on the property.
For additional information regarding the definitions contained in this Glossary, or for other
Oil & Gas definitions, please see Rule 4-10 of Regulation S-X.
SIGNATURES
Pursuant to the requirements of Section 13 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 on February 22, 2013.
McMoRan Exploration Co.
By: /s/ James R. Moffett
James R. Moffett
Co-Chairman of the Board,
President and Chief Executive Officer
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 the capacities indicated, on February 22, 2013.
/s/ James R. Moffett
Co-Chairman of the Board, President
and Chief Executive Officer
James R. Moffett
/s/ Richard C. Adkerson
Co-Chairman of the Board
Richard C. Adkerson
*
Vice Chairman of the Board
B.M. Rankin, Jr.
/s/ Nancy D. Parmelee
Senior Vice President, Chief Financial
Nancy D. Parmelee
Officer and Secretary
(Principal Financial Officer)
*
Vice President and Controller - Financial Reporting
C. Donald Whitmire, Jr.
(Principal Accounting Officer)
*
Director
A. Peyton Bush, III
*
Director
William P. Carmichael
*
Director
Robert A. Day
*
Director
James C. Flores
*
Director
Gerald J. Ford
*
Director
H. Devon Graham, Jr.
*
Director
Suzanne T. Mestayer
*
Director
John F. Wombwell
*By: /s/ Richard C. Adkerson
Richard C. Adkerson
Attorney-in-Fact
S-1
McMoRan Exploration Co.
Exhibit Index
E-1
E-2
E-3
E-4
-------------------------
* Indicates management contract or compensatory plan or agreement.
E-5