PROSPECTUS SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus and does not contain all of the information that you should consider before investing in our Class A common stock. You should read the entire prospectus carefully before making an investment decision, including the information presented under the headings “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Unless otherwise indicated, the information presented in this prospectus assumes that the underwriters’ option to purchase additional shares of Class A common stock from us is not exercised. Several terms used in this prospectus are defined in the “Glossary.” References to our estimated proved, probable and possible reserves, standardized measure and PV-10 are derived from our reserve reports prepared by our external, independent petroleum engineering firms Netherland, Sewell & Associates, Inc., which we refer to as NSAI, and Ryder Scott Company, L.P., which we refer to as Ryder Scott.

In this prospectus, unless the context otherwise requires, the terms “we,” “us,” “our,” and “FCX O&G” refer to FCX Oil & Gas Inc. and its subsidiaries before the completion of our corporate reorganization prior to the closing of this offering, and Freeport-McMoRan Oil & Gas Inc., which we refer to as “FM O&G Inc.” and its subsidiaries as of the completion of our corporate reorganization and thereafter. The term “FCX” refers to Freeport-McMoRan Inc., our direct parent after completion of our corporate reorganization. See “Corporate Reorganization.”

Our Company

We are an upstream oil and gas energy company primarily engaged in acquiring, exploring for, developing and producing oil and gas properties. We are focused on growing our strategic position in the Deepwater U.S. Gulf of Mexico, which we refer to as the Deepwater GOM. Our Deepwater GOM position has significant current oil production, strong cash margins and existing infrastructure with excess production and handling capacity. We expect this existing infrastructure and our extensive inventory of drilling opportunities will allow us to grow our Deepwater GOM production with comparatively low capital expenditures. In addition, our onshore and offshore properties in California are characterized as low-decline properties with stable production and long-lived reserves. We also have a large, onshore gas position in the Haynesville shale and the Inboard Lower Tertiary/Cretaceous gas trend located onshore in South Louisiana. Our Madden field in Central Wyoming also provides us with additional predictable cash flows, low-decline production and long-lived gas reserves. Our gas-weighted assets position us to benefit from a recovery in gas prices. We are currently focused on growing our proved reserves and production by developing our oil-weighted properties in the Deepwater GOM with a prudent capital profile for the current commodity price environment.

We believe our portfolio of oil and gas properties delivers financially attractive investment opportunities with growth potential in terms of production, cash margin and reserves. For the six months ended June 30, 2015, 88 percent of our oil and gas revenues, excluding the impact of derivative contracts, was from oil and NGLs. Our oil and gas business has significant proved, probable and possible reserves and a broad range of additional development opportunities, including discoveries and identified prospects in the Deepwater GOM. A significant portion of our planned capital expenditures are expected to be focused on converting our probable and possible reserves and prospective resources to the proved reserves category as we are focused on developing our relatively low-risk near-term Deepwater GOM inventory. We strive to manage our business to reinvest cash flows in projects with attractive risk-adjusted rates of return.

Based on data derived from reserve reports prepared by our external, independent petroleum engineering firms, our estimated oil and gas reserves at December 31, 2014 were as follows:

Our acreage position was 1,022,537 gross (436,189 net) developed acres and 4,017,361 gross (2,458,424 net) undeveloped acres at December 31, 2014. At December 31, 2014, we owned working interests in 3,069 gross (2,991 net) active producing oil wells and 1,710 gross (211 net) active producing gas wells. For the six months ended June 30, 2015, we generated sales volumes of 142 MBoe/d with realized revenues, including cash gains on derivatives, of $46.95 per Boe and cash production costs of $19.62 per Boe. Realized revenue and cash production costs are non-GAAP financial measures. Revenue and production costs, respectively, are the most directly comparable GAAP measure, which were $41.35 per Boe and $22.01 per Boe, respectively, for the six months ended June 30, 2015. See “Summary Consolidated Financial, Reserve and Operating Data—Non-GAAP Financial Measures.”

Deepwater GOM Producing Assets, Sanctioned Discoveries and Associated Drilling Inventory

We have a large strategic position in the Deepwater GOM with significant current oil production, strong cash margins and existing infrastructure with excess production and handling capacity. These assets, combined with our large leasehold interests, provide financially attractive near-term drilling opportunities for growth in oil production and cash margins. Our properties and activities are principally located in four focus areas, which we refer to as Atwater Valley, Green Canyon, Mississippi Canyon and Keathley Canyon. Furthermore, our capital allocation strategy is principally focused on drilling wells that can be tied back expeditiously to our existing facilities. We have adopted a prudent capital profile for the current commodity price environment in which we have deferred certain capital associated with completion and infrastructure spending and are electing to defer production growth for potentially more favorable market conditions. We believe our existing infrastructure provides us with a competitive advantage by allowing for flexibility to control the pace of our development and production activities for relatively low amounts of investment capital as compared to competitors who lack access to such facilities. In addition, we expect to apply existing technologies in subsea pumping and lifting technology to our properties. This technology can provide the potential for increasing hydrocarbon recovery by boosting pressure required for delivery at the existing host platform.

The following is a summary of our Deepwater GOM platforms and currently producing fields at June 30, 2015:

Since the acquisition of our Holstein, Marlin Hub and Horn Mountain properties from subsidiaries of BP p.l.c., which we refer to as BP, and Royal Dutch Shell p.l.c., which we refer to as Shell, in November 2012, we have been active in optimizing production from existing wells through well workover and stimulation activities in previously developed formations. The significant production history from these assets, together with extensive reservoir modeling and multiple series of seismic evaluation and interpretation, gives us high confidence in achieving positive results in our planned near-term development drilling activities.

Our planned development activities associated with our Deepwater GOM producing assets targeting known productive pay sand in these fields are listed below.

Holstein. In 2014, we commenced a program to redevelop Holstein and successfully drilled two sidetrack wells utilizing our owned platform drilling rig. Our future plans for Holstein include additional sidetracks and drilling activities. In addition, we have made a significant discovery in deeper subsalt Miocene reservoirs at Holstein, which we refer to as Holstein Deep, and we are developing this discovery by means of a subsea tieback with the potential to apply existing subsea enhancement technologies that could increase total recovery efficiencies for the project.

Marlin Hub. Activities in the Marlin Hub area have focused on infield drilling at the Dorado and King fields, which are produced through subsea tie back to the Marlin platform. In December 2014, we successfully drilled a development well at Dorado that encountered 245 net feet of Miocene oil pay. This well was placed on production in March 2015 after a successful production test with gross volumes in excess of seven MBbls of oil per day and eight MMcf of gas per day and continues to produce at strong rates. At King, we drilled a development well in January 2015 and logged 63 net feet of Miocene oil pay. We subsequently sidetracked and completed this well for an optimum oil take point, and we expect to place this well on production in 2015. Our future plans at Dorado and King include additional drilling in the same Miocene horizons in the second half of 2015 and in 2016. In addition, we have identified prospective drilling at King in deeper horizons, which we refer to as King West Deep. Future wells in the Marlin Hub area can be brought on-line expeditiously through our existing infrastructure and future subsea tiebacks have the potential to utilize existing subsea enhancement technologies that could increase total recovery efficiencies. In second-quarter 2015, we completed maintenance activities, including installation of new export flow line flex joints, which will extend the life of the Marlin platform.

Horn Mountain. Our producing wells in the Horn Mountain field target formations similar to those in the Marlin Hub area and are located in the same geologic setting as our production from the Dorado and King fields. The currently producing wells use dry trees to connect to the Horn Mountain spar. To enhance our recovery of remaining oil in place, our future development plan anticipates utilizing subsea tieback wells targeting multiple stacked sands. During the three months ended June 30, 2015, the Quebec/Victory well, the first location of this program, was drilled to 14,780 feet and we have logged 355 net feet of oil and gas pay. Upon completion, we plan to put this well on production in 2016. In June 2015, drilling operations commenced at the Kilo/Oscar and Horn Mountain Updip wells. At Kilo/Oscar, the well was drilled to a total depth of 14,250 feet and successfully logged 166 net feet of oil pay. At Horn Mountain Updip, the well was drilled to a total depth of 14,780 feet and successfully logged 112 net feet of oil and gas pay. This infill development drilling program will target hydrocarbon accumulations in the sands found to be productive at Horn Mountain and, in addition to these three wells, consists of the Horn Mountain Northwest, Eland/Zebra, Sable and Lion locations. In addition, we have identified prospective drilling in deeper horizons, which we refer to as Horn Mountain Deep which we plan to spud in third-quarter 2015. All planned and prospective drilling at Horn Mountain has the potential to utilize existing subsea enhancement technologies that could increase total recovery efficiencies.

Lucius. In January 2015, we began production from an initial six-well development in the Lucius field operated by Anadarko Petroleum Corporation, which we refer to as Anadarko. During the three months ended June 30, 2015, the Lucius Oil Facility reached capacity of 80 MBbls of oil per day. Lucius is a world-class subsalt Pliocene and Miocene discovery with high-quality reservoir attributes. We participated in the drilling of the discovery well in 2009 and increased our working interest through an acquisition in 2014. In 2011, we and the other working interest owners sanctioned the spar construction, with initial development focused primarily on the Pliocene-aged sands with average net pay thickness of 469 feet. In addition, we have identified further

drilling opportunities in the Pliocene and Miocene horizons at Lucius. Our Lucius development is an example of how historically we have partnered with third party capital providers to finance development costs related to our Deepwater GOM properties. In 2011, subsequent to the Lucius discovery well, we raised $450 million through the issuance of convertible preferred stock in one of our subsidiaries that holds a portion of our interest at Lucius.

Ram Powell. In March 2015, Shell successfully drilled a development well at Ram Powell logging 106 feet of pay in above salt Miocene reservoirs. The well has been completed and came online in July 2015.

In addition to our activities on our producing fields we own interests in and have been actively developing two discoveries that have been sanctioned for development. Both of these discoveries are located in our Green Canyon focus area and target subsalt Miocene reservoirs.

The following table provides a summary of our active development projects:

Holstein Deep. This large, high-quality subsalt Miocene oil discovery has the potential to be a phased development project tied back to the Holstein spar. In December 2014, we achieved successful results from a Holstein Deep delineation well that logged 444 feet of net oil pay. In February 2015, we completed drilling the second delineation well, with positive results. This second well encountered 482 feet of net oil pay. The third delineation well was drilled to 29,440 feet and encountered approximately 200 feet of net oil pay. Drilling results from this initial three-well development program successfully established sand continuity across the primary reservoir. Production from this initial three-well development is expected to begin in 2016 with estimated risk-adjusted gross initial individual well flowrates of 8 MBbls of oil per day. We believe that when fully developed this project could have the potential to produce up to 75 MBbls of oil per day.

Heidelberg. The initial Heidelberg discovery well was drilled in 2009 and encountered more than 200 net feet of oil pay. Log and pressure data from the discovery and delineation wells indicate excellent quality, continuous and pressure-connected reservoirs with subsalt Miocene oil. The Heidelberg working interest owners sanctioned a six well development plan, with a new truss spar facility having a design capacity of 80 MBbls of oil per day. Completion activities on the three initial wells are in progress. Fabrication of the main topsides module is complete, the hull is on location, the mooring lines are completed, and the project remains on track for first production in 2016 with anticipated risk-adjusted gross initial individual well flowrates of 10.4 MBbls of oil per day.

Deepwater GOM Discoveries in Pre-Sanction Stage with Potential Development Opportunities

In addition to our discoveries that have been sanctioned for development, we own working interests in several additional significant oil discoveries that could provide additional production reserves and drilling opportunities. These discoveries consist of subsalt Miocene and Lower Tertiary formations located in our Atwater Valley and Keathley Canyon focus areas. These discoveries hold significant potential and the timing of their development will be dependent on finalization of development plans and sanctioning by us and our partners.

The following table provides a summary of our discoveries that are in the pre-sanctioning phase:

Vito and Power Nap. Vito is a large, deep subsalt Miocene oil discovery made in 2009. Exploration and delineation drilling in recent years confirmed a significant resource in high-quality, subsalt Miocene sands with an average net pay of 457 feet. Development options are under evaluation by the working interest owners, and we expect Shell, as the operator, to propose a sanctioning development plan for 2016. Power Nap is located in close proximity to Vito where we encountered positive drilling results in December 2014 in the same sands as Vito. Delineation drilling activities consisting of two sidetracks have confirmed the findings in the initial well. The working interest owners are currently evaluating development options for Power Nap.

Phobos. In 2013, the initial Phobos discovery well, located in the Sigsbee Escarpment area, was drilled and encountered more than 250 net feet of pay in Lower Tertiary reservoirs. We expect a potential Phobos development to benefit from its close proximity to the Lucius spar. The working interest owners are evaluating future plans for this discovery.

Deepwater GOM Prospect Inventory and Drilling Plans

In addition to the proved, probable and possible reserves and prospective resources associated with our Deepwater GOM producing assets and Deepwater GOM discoveries, we have a large inventory of identified prospects with production and resource potential. Our inventory consists of both above salt and subsalt formations and is focused on resources that, upon success, we plan to tieback to our Holstein, Horn Mountain, Marlin and Lucius platforms or can be developed in conjunction with our Vito and Power Nap discoveries, should those discoveries be sanctioned for development. Our operational control and remaining primary term lease position for these prospects allows us the ability to modify the timing of when we expect to drill the initial well in these prospects. We target resources primarily in Pliocene and Miocene reservoirs but also have large prospects in the Lower Tertiary.

Our Deepwater GOM prospect inventory consists of interests in 16 prospects, which were identified by seismic imaging and which include 154 undeveloped well locations. The following table provides a summary of prospects and projected spud dates. The commercial success of these prospects would likely lead to a large number of additional drilling opportunities in the future.

Exploration

Utilizing seismic interpretation, we intend to identify areas for potential hydrocarbon accumulations and add to this undrilled inventory through farm outs, acquisitions and participation in future BOEM lease sales. Also, as part of our exploration efforts, we regularly collaborate with experienced and respected large independent, major integrated and international state owned oil and gas energy companies on geologic and engineering studies covering currently owned leasehold and uncaptured domestic and international acreage. We believe these efforts will enable us to enhance and optimize our undrilled portfolio.

Our prospect generation approach is predicated upon a thorough, basin-wide understanding of the geologic trends within our focus areas through a detailed review of industry drilling results, followed by a rigorous analysis and reprocessing of our basin wide, focused 3-D seismic data. Consistent with our approach and to drive the internal generation and acquisition of new prospects, we have made significant investments in the latest

seismic data and seismic imaging technology. Since 2006, we have spent in excess of $300 million on the acquisition, reprocessing and analysis of extensive geophysical data in the Deepwater GOM. We currently own or have licensed 3-D seismic data covering over 5,000 blocks in the Deepwater GOM. Our seismic data base includes the most recent advanced technologies, including wide-azimuth 3-D data. Wide-azimuth 3-D seismic data generates substantially more accurate images than traditional 3-D seismic data, helping to reduce exploration risk. Wide-azimuth 3-D seismic data is critical to understanding of a particular reservoir’s characteristics, including trapping mechanics and fluid migration patterns. Additionally, we utilize 4-D seismic data, which is a series of 3-D seismic surveys repeated over a period of time. Our technical team also regularly makes use of advanced seismic imaging technology including pre-stack depth migration, which is a technique that uses advanced processing algorithms to transform seismic data from a scale of time to a scale of depth.

Our Holstein Deep, Phobos, Highlander, Vito and Power Nap discoveries are evidence of a successful prospect generation approach coupled with advanced seismic data that resulted in discoveries of significant hydrocarbon reservoirs. We believe that these discoveries will add to our proved reserve base over time. We expect to add Holstein Deep and Highlander reserves starting this year. Going forward we expect that new prospects generated through our exploration efforts will typically target formations with gross hydrocarbon potential in excess of 100 MMBoe. We expect our exploration process and our collaboration with other companies that have comparable technology and technical expertise to continue to provide significant high-quality prospects. Capri and Eagle are two of our long term exploration prospects and are examples of interests acquired through BOEM lease sales, that are currently being matured. Future drilling decisions for these or other prospects will be driven by the results of our exploration process and capital budget considerations. In the current commodity price environment we intend to significantly reduce spending on our exploration inventory in the near term.

In addition to employing our exploration process and technical capabilities in the U.S., we have in the past explored for hydrocarbons internationally and may do so in the future. Currently, we have licenses to 1,662 square miles of 3-D seismic data covering deepwater areas, offshore Morocco. Further, we have been pre-qualified as a bidder in the upcoming Mexican lease sale and we are in the early stages of evaluating the hydrocarbon potential of Mexico.

California Assets

Our California assets provide an established oil production base with low-decline production profiles, long-lived reserves and significant exposure to an improving oil market. Our onshore California properties are primarily located in the Los Angeles Basin and San Joaquin Valley. We hold a 100 percent working interest in the substantial majority of our onshore position. The Los Angeles Basin properties are characterized by light crude oil, have well depths ranging from 2,000 feet to over 10,000 feet and include both primary production and secondary recovery using waterflood methods, and produce with high water cuts. The San Joaquin Basin properties are characterized by heavier oil and shallow wells (generally less than 2,000 feet) that require enhanced oil recovery techniques, including steam injection. Our offshore California properties are primarily located in the Point Arguello and Point Pedernales fields, where we hold a 69.3 percent and 100 percent working interest, respectively. In 2015, we plan to focus our operating and capital expenditures in California on high-margin re-completion and well maintenance activities. For the six months ended June 30, 2015, our California assets produced 39.0 MBoe/d. In 2016 we plan to focus our drilling activities in the Cymric field, our largest property in California.

Gas-Weighted Assets

We own a substantial portfolio of gas-weighted assets, including a large position in the Haynesville shale in Louisiana, a position in the Inboard Lower Tertiary/Cretaceous gas trend located onshore in South Louisiana, producing properties on the shelf of the Gulf of Mexico, which we refer to as the GOM Shelf, and a position in the Madden field located in Central Wyoming. As of December 31, 2014, in the Haynesville shale, we have a non-operated interest in over 1,400 producing wells with an average working interest of 8.5 percent and leases covering 75,000 net acres. We estimate the potential to drill an additional 12,000 gross (1,000 net) wells on our Haynesville shale acreage. In the Lower Tertiary/Cretaceous we have recently experienced success from a production test indicating a flow rate of 75 MMcf/d. The Highlander well, which has been restricted because of limited processing facilities, averaged a gross rate of 22 MMcf/d (approximately 11 MMcf/d net) during the quarter ended June 30, 2015. We are developing additional processing facilities to accommodate the higher flow rates with installation expected by year-end 2015. In July 2015, the Highlander well was shut in for remedial workover operations to address a mechanical issue encountered in the wellbore. A second well location has been identified and future plans are being considered. Our gas-weighted assets in Louisiana are geographically positioned to benefit from the expected growth in gas demand from existing and planned LNG terminals and petrochemical plants along the Gulf Coast. We also own interests in gas-weighted properties in the GOM Shelf in Louisiana. Further, our approximate non-operated 14 percent working interest in the Madden Deep Unit and Lost Cabin Gas Plant in Wyoming provides us with low-decline stable cash flows with long reserve life. Our large resource and acreage position provides us with the opportunity for significant reserve and production growth on a rapidly scalable basis upon a return of a more favorable gas price environment. For the six months ended June 30, 2015, our gas-weighted assets produced 233.8 MMcfe/d.

Our 2015 Capital Budget

We estimate our fiscal 2015 capital budget will be $2.8 billion (of which $1.8 billion was spent for the six months ended June 30, 2015). This capital budget reflects our focus on growth of production and reserves, as well as executing on our inventory of discoveries and prospects in the Deepwater GOM. Our 2015 capital budget includes:

Our 2016 Capital Budget

We estimate our fiscal 2016 capital budget will be $2.0 billion. This capital budget reflects our conservative strategy of moderate production growth in the current commodity price environment. The majority of capital budget in 2016 will be allocated to operated properties focused on development in the Deepwater GOM, giving us increased flexibility to respond to more favorable commodity pricing. We plan to engage third party investors and industry partners to further delineate our existing discoveries and test our prospects in the Atwater Valley focus area. We have elected to defer capital spending and associated production growth for more favorable market conditions. We also plan to defer exploratory spending to future periods. Our 2016 capital budget includes:

We have made, and expect to make in 2015, 2016 and beyond, substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of reserves, as well as the development and maintenance of necessary infrastructure and other items. We may not have sufficient resources to undertake these activities. For more information, see “Risk Factors—Risks Related to Our Business—Our business plan requires substantial additional capital, which we may be unable to raise on acceptable terms in the future, which may in turn limit our ability to execute our business plan and could lead to a loss of properties and have a material adverse effect on our production, reserves and results of operations.”

Our Competitive Strengths

We have a number of competitive strengths that we believe will help us to successfully execute our business strategies, including:

In addition to current production, we believe that our Deepwater GOM properties have attractive production growth profiles in well-defined areas driven by our key discoveries and identified prospects. Our existing infrastructure enables us to develop resources using subsea tiebacks. This infrastructure position allows us to reduce the time from investment to first production and our capital costs have the potential to be lower when compared to other operators with similar prospects that lack infrastructure capacity. This is evidenced by our recent Dorado well that was brought on-line within five months of spud and our Holstein Deep and Horn Mountain developments, which we expect to begin production in

2016. Our non-operated interests in the Lucius and Heidelberg are expected to provide additional production growth and our discoveries at Vito and Power Nap have a potential to add value upon their potential sanctioning. Our plan for developing our Deepwater GOM portfolio provides opportunities for near-term cash generation, reserve replacement and long-term production growth.

Our Business Strategy

Our strategy consists of the following principal elements:

Risk Factors

Investing in our Class A common stock involves risks that include the speculative nature of oil and gas exploration, competition, volatile commodity prices and other material factors. For a discussion of these risks and other considerations that could negatively affect us, including risks related to this offering and our common stock, see “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

Our Relationship with FCX

Our principal stockholder is FCX, a leading international natural resources company with headquarters in Phoenix, Arizona. FCX operates large, long-lived, geographically diverse assets with significant reserves of copper, gold, molybdenum, cobalt, crude oil and gas.

FCX currently owns 100 percent of our Class A and Class B common stock. Upon completion of this offering, FCX will hold             shares of Class B common stock, representing      percent of our total outstanding shares of common stock, 100 percent of our total outstanding shares of Class B common stock, and      percent of the combined voting power of our outstanding common stock upon completion of this offering (or      percent, 100 percent and      percent, respectively, if the underwriters’ option to purchase additional shares of Class A common stock from us is exercised in full). We also expect to enter into several agreements with FCX at the

closing of this offering, including a tax matters agreement, an intercompany loan agreement, a shared services agreement, a transaction agreement and a stockholders agreement. For a description of these agreements, see “Certain Relationships and Related Party Transactions.” For more information regarding risks related to our relationship with FCX, see “Risk Factors,” including “Risk Factors—Risks Relating to this Offering and Our Class A Common Stock.”

Corporate Information

Our principal executive offices are located at 700 Milam, Suite 3100, Houston, Texas 77002, and our telephone number is (713) 579-6000. Our website is www.            .com. We expect to make our periodic reports and other information filed with or furnished to the SEC available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

THE OFFERING

The information above excludes             shares of Class A common stock reserved for issuance under the Freeport-McMoRan Oil & Gas Inc. 2015 Incentive Award Plan. See “Management—2015 Incentive Plan.”

SUMMARY CONSOLIDATED FINANCIAL, RESERVE AND OPERATING DATA

The following summary consolidated financial, reserve and operating data should be read in conjunction with, and are qualified by reference to, “Selected Historical Consolidated Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Corporate Reorganization” and the consolidated financial statements and related notes contained elsewhere in this prospectus.

On May 31, 2013, FCX acquired Plains Exploration & Production Company, which we refer to as the Predecessor or PXP, through a merger into Freeport-McMoRan Oil & Gas LLC, which we refer to as FM O&G LLC, a wholly owned subsidiary of FCX O&G, which we refer to as the Successor. On June 3, 2013, FCX acquired McMoRan Exploration Co., which we refer to as McMoRan, which became a wholly owned subsidiary of FCX O&G. The below selected unaudited pro forma consolidated information as of and for the six months ended June 30, 2015, and for the year ended December 31, 2014, relates to the Successor. The below summary consolidated financial data as of and for the six months ended June 30, 2015, for the six months ended June 30, 2014, as of and for the year ended December 31, 2014, as of December 31, 2013, and for the period from April 23, 2013, to December 31, 2013, relates to the Successor. The results included in the summary financial data for the period from April 23, 2013, to December 31, 2013, include PXP’s results beginning June 1, 2013, and McMoRan’s results beginning June 4, 2013. The Successor’s oil and gas operations commenced on June 1, 2013. The below summary consolidated financial data for the period from January 1, 2013, to May 31, 2013, and as of and for the years ended December 31, 2012, 2011 and 2010, relates to the Predecessor.

The unaudited pro forma information of FCX O&G gives effect to (i) the expected sale of              shares of Class A common stock, the use of proceeds from the sale of the Class A common stock and the proposed corporate reorganization (which, among other things will result in the elimination of our revolving notes and other long-term debt, including our senior notes) and (ii) the Eagle Ford shale divestment. The unaudited pro forma condensed consolidated statement of operations for the six months ended June 30, 2015, gives effect to the expected sale of equity securities as if the sale had occurred on January 1, 2014; the unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 2014, gives effect to the expected sale of equity securities and the Eagle Ford shale divestment as if the transactions had occurred on January 1, 2014; and the unaudited pro forma condensed consolidated balance sheet gives effect to the expected sale of Class A common stock securities as if it had occurred on June 30, 2015. This unaudited pro forma condensed consolidated financial data is provided for information purposes only and does not purport to represent what the actual results of operations or financial position would have been if these transactions had occurred on the dates assumed. The unaudited pro forma condensed consolidated financial data should be read together with the historical financial statements and the pro forma condensed consolidated financial statements included elsewhere in this prospectus.

The summary historical consolidated statements of operations data and statements of cash flow data for the six months ended June 30, 2015 and 2014, and the summary historical consolidated balance sheet data as of June 30, 2015, were derived from the unaudited consolidated financial statements of the Successor included elsewhere in this prospectus. These statements have been prepared on a basis consistent with the audited consolidated financial statements of the Successor. In the opinion of management, such unaudited financial data reflects all adjustments, consisting only of normal and recurring adjustments, necessary for a fair presentation of the results for such period. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year or any future period.

We derived the summary historical consolidated statements of operations data and statements of cash flow data for the year ended December 31, 2014, and for the period from April 23, 2013, to December 31, 2013, and the summary historical consolidated balance sheet data as of December 31, 2014 and 2013, from the audited consolidated financial statements of the Successor included elsewhere in this prospectus.

We derived the summary historical consolidated statements of operations data and statements of cash flow data for the period from January 1, 2013, to May 31, 2013, and for the year ended December 31, 2012, from the audited consolidated financial statements of the Predecessor included elsewhere in this prospectus.

Summary Consolidated Financial Data

Summary Reserve Data

The following tables present summary data with respect to our estimated proved, probable and possible reserves as of the dates indicated. The reserve estimates presented in the table below are based on reserve reports prepared by NSAI and Ryder Scott in accordance with the rules and regulations of the SEC regarding oil and gas reserve reporting. For more information about our proved, probable and possible reserves, see NSAI’s and Ryder Scott’s reserve reports, which are filed as exhibits to the registration statement of which this prospectus forms a part. We determined our possible reserves to be either developed or undeveloped using methodology similar to that used by NSAI and Ryder Scott in the preparation of their reserve reports.

Non-GAAP Financial Measures

Adjusted EBITDA

Adjusted EBITDA is used as a supplemental financial measure by management and by external users of our consolidated financial statements, such as investors, commercial banks, research analysts and others, to assess: (i) the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; (ii) our operating performance and return on capital as compared to those of other companies in the upstream energy sector, without regard to financing or capital structure; and (iii) the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

Our calculation of Adjusted EBITDA may not be comparable to other similar measures used by other companies and you should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP.

The following table presents a reconciliation of the GAAP financial measure of consolidated net income (loss) attributable to common stockholders to Adjusted EBITDA for the periods indicated:

PV-10

PV-10 is a non-GAAP financial measure and is derived from Standardized Measure, which is the most directly comparable GAAP financial measure. PV-10 is equal to the Standardized Measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the relative monetary significance of our properties regardless of tax structure. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our proved reserves to other companies. We use this measure when assessing the potential return on investment related to our oil, gas and NGL properties. However, PV-10 is not equal to, nor a substitute for, the Standardized Measure of discounted future net cash flows. Our PV-10 and the Standardized Measure of discounted future net cash flows do not purport to present the fair value of our proved reserves. The following table provides a reconciliation of PV-10 to the GAAP financial measure of Standardized Measure for the periods indicated:

Realized Revenue and Cash Production Costs per Boe

Realized revenues and cash production costs per Boe are measures intended to provide information about the cash operating margin of our oil and gas operations and for monitoring our operation performance against other oil and gas companies. We show revenue adjustments from derivative contracts as separate line items because these adjustments do not result from oil and gas sales, these gains and losses have been reflected separately from revenues on current period sales. Additionally, accretion charges for asset retirement obligations and other costs are removed from production costs in the calculation of cash production costs per Boe. This information differs from measures of performance determined in accordance with GAAP and should not be considered in isolation or as a substitute for measures of performance determined in accordance with GAAP. The following schedules include calculations of oil and gas realized revenues and cash production costs per Boe together with reconciliations to revenue and production costs.

Summary Operating Data

The following table sets forth summary data with respect to our production results, average realized prices and certain expenses on a per Boe basis for the periods indicated: