Exhibit 99.2

SUMMARY

This summary highlights information appearing elsewhere in this offering memorandum. This summary is not complete and does not contain all of the information that you should consider before investing in the notes. You should carefully read the entire offering memorandum, including the information presented under “Risk Factors,” “Disclosure Regarding Forward-Looking Statements” and “Incorporation by Reference.”

Except as otherwise indicated or unless the context otherwise requires, the terms “EP Energy,” “we,” “us,” “our,” “the Company” and “our company” refer to EP Energy LLC and its subsidiaries. Certain oil and gas industry terms used in this offering memorandum are defined in the “Glossary of Oil and Natural Gas Terms” beginning on page A-1 of this offering memorandum.

Unless otherwise indicated or the context otherwise requires, references in this offering memorandum to “we,” “our,” “us,” and the “Company” refer to EP Energy LLC (the “Issuer”) and each of its consolidated subsidiaries, including Everest Acquisition Finance Inc. (the “Co-Issuer” and, together with the Issuer, the “Issuers”). Estimates of our oil, natural gas and NGLs reserves, related future net cash flows and the present values thereof as of December 31, 2014 incorporated by reference into this offering memorandum were prepared by our internal staff of engineers and audited by the independent petroleum engineering consultant firm of Ryder Scott Company, L.P. (“Ryder Scott”).

Our Company

We are an independent exploration and production company engaged in the acquisition and development of unconventional onshore oil and natural gas properties in the United States. We are focused on creating value through the development of our low-risk drilling inventory located predominantly in four operating areas: the Eagle Ford Shale (South Texas), the Wolfcamp Shale (Permian Basin in West Texas), the Altamont Field in the Uinta Basin (Northeastern Utah) and the Haynesville Shale (North Louisiana). In our operating areas, we have identified 5,673 drilling locations (including 979 drilling locations to which we have attributed proved undeveloped reserves as of December 31, 2014, of which approximately 92% are oil wells). At 2014 activity levels, this represents approximately 21 years of drilling inventory (more than 30 years of drilling inventory at 2015 drilling levels). As of December 31, 2014, we had proved reserves of 622.2 MMBoe (52% oil and 67% liquids) and for the quarter ended March 31, 2015, we had average net daily production of 102,421 Boe/d (59% oil and 70% liquids).

Our management team has significant experience identifying, acquiring and developing unconventional oil and natural gas assets. The majority of our senior management team has worked together for over a decade at prominent oil and gas companies that have included El Paso Corporation, ConocoPhillips and Burlington Resources. We believe our management’s experience in both acquiring resource-rich leasehold positions and efficiently developing those properties will enable us to generate attractive rates of return from our capital programs.

Each of our operating areas is characterized by a favorable operating environment, a long-lived reserve base and high drilling success rates. We have established significant contiguous leasehold positions in each area, representing approximately 477,000 net (647,000 gross) acres in total. Beginning in 2012, our capital programs have focused predominantly on the Eagle Ford Shale, the Wolfcamp Shale and Altamont, three of the premier unconventional oil plays in the United States, resulting in oil reserve and production growth of 10% and 51%, respectively, from December 31, 2013 to December 31, 2014.

Prior to 2014, we divested our non-core domestic natural gas assets and an equity investment for a total consideration of approximately $1.5 billion. As a result of these asset sales, we became a growth-oriented, 100% onshore, oil-weighted company with a large inventory of low-risk drilling locations. While we continue to principally focus on the development of our oil-weighted assets, our Haynesville Shale position gives us the flexibility to allocate capital to natural gas production based on changes in commodity prices and rates of return.

The following table provides a summary of oil, natural gas and NGLs reserves as of December 31, 2014 and production data for the quarter ended March 31, 2015 for each of our areas of operation. Our estimated proved reserves have been prepared by our internal reserve engineers and audited by Ryder Scott Company, L.P., our independent petroleum engineering consultants since 2004.

(1)                                 Proved reserves were evaluated using first day 12- month prices of $94.99 per barrel of oil (WTI) and $4.34 per MMBtu of natural gas (Henry Hub).

(2)                                 Comprised of outside operated overriding interests in the Gulf of Mexico and Rockies.

Our Properties and Operating Areas

Eagle Ford Shale.  The Eagle Ford Shale, located in South Texas, is one of the premier unconventional oil plays in the United States. We were an early entrant into this play in late 2008, and since that time have acquired a leasehold position in the core of the oil window, primarily in La Salle County. The Eagle Ford formation in La Salle county has up to 125 feet of net thickness (165 feet gross). Due to its high carbonate content, the formation is also very brittle, and exhibits high productivity when fractured. As of December 31, 2014, we had 81,753 net (88,890 gross) acres in the Eagle Ford, and we have identified 872 drilling locations.

During 2014, we invested $1,087 million in capital expenditures in our Eagle Ford Shale and operated an average of 5.5 drilling rigs. As of March 31, 2015, we had 439 net producing wells (436 net operated wells) and are currently running three rigs. For the quarter ended March 31, 2015, our average net daily production was 54,709 Boe/d, representing growth of 18% over the same period in 2014. For the year ended December 31, 2014 our average cost per gross well was $7.2 million ($6.8 million per net well).

Wolfcamp Shale.  The Wolfcamp Shale is located in the Permian Basin. The Permian Basin is characterized by numerous, stacked oil reservoirs that provide excellent targets for horizontal drilling. In 2009 and 2010, we leased 138,130 net (138,469 gross) acres on the University of Texas Land System in the Wolfcamp Shale, located primarily in Reagan, Crockett, Upton and Irion counties. In 2014, we acquired producing properties and undeveloped acreage in the Southern Midland Basin, of which 37,000 net acres are adjacent to our existing Wolfcamp Shale position. The acquisition represented an approximate 25% expansion of our Wolfcamp acreage.

Our large, contiguous acreage positions are characterized by stacked pay zones, including the Wolfcamp A, B, and C, which combine for over 750 feet of net (approximately 1,000 feet of gross) thickness. The Wolfcamp has high organic content and is composed of interbedded shale, silt, and fine-grained carbonate that respond favorably to fracture stimulation. As of December 31, 2014, we have 179,780 net (181,487 gross) acres in the Wolfcamp, in which we have identified approximately 3,300 drilling locations in the Wolfcamp A, B, and C. In the second half of 2014, we initiated drilling in the Wolfcamp A.

The acreage is also prospective for the Cline Shale, which has approximately 100 feet of net (approximately 200 feet of gross) thickness, and potential vertical drilling locations in the Spraberry and other stacked formations.

During 2014, we invested $822 million in capital expenditures (including $158 million of acquisition capital) in our Wolfcamp Shale and operated an average of 3.5 drilling rigs. As of March 31, 2015, we had 214 net operated producing wells. We are currently running one rig. For the quarter ended March 31, 2015, our average net daily production was 17,923 Boe/d, representing growth of 50% over the same period in 2014. For the year ended December 31, 2014, our average cost per gross well was $6.2 million ($6.2 million per net well).

Altamont.  The Altamont field is located in the Uinta Basin in northeastern Utah. The Uinta Basin is characterized by naturally fractured, tight-oil sands and carbonates with multiple pay zones. Our operations are primarily focused on developing the Altamont Field Complex (comprised of the Altamont, Bluebell and Cedar Rim fields), which is the largest field in the basin. We own 177,119 net (319,600 gross) acres in Duchesne and Uinta Counties. The Altamont Field Complex has a gross pay interval thickness of over 4,300 feet and we believe the Wasatch and Green River formations are ideal targets for low-risk, infill, vertical drilling and modern fracture stimulation techniques. Our commingled production is from over 1,500 feet of net stimulated rock. Our current activity is mainly focused on the development of our vertical inventory on 80-acre and 160-acre spacing. As of December 31, 2014, we have identified 1,304 drilling locations (1,295 vertical and 9 horizontal). The industry has piloted 80-acre vertical downspacing and in November 2014 the Utah Board of Oil, Gas and Mining approved 80-acre well density on approximately 50,000 acres of our Altamont net acreage. Industry activity has also focused on horizontal drilling in the Wasatch and Green River formations testing tight carbonate and sand intervals. Due to the largely held-by-production nature of our acreage position, if these programs are successful, it will result in additional vertical and horizontal drilling opportunities that could be added to our inventory of drilling locations.

During 2014, we invested $283 million in capital expenditures in the Altamont Field, operated an average of three drilling rigs, and drilled 47 operated gross wells. As of March 31, 2015, we had 368 net producing wells (360 net operated wells). We are currently running two rigs. For the quarter ended March 31, 2015, our average net daily production was 17,079 Boe/d, representing growth of 27% over the same period in 2014. For the year ended December 31, 2014 our average cost per gross well was $5.2 million ($4.4 million per net well).

Haynesville Shale.  In addition to our oil programs, we hold significant natural gas assets in the Haynesville Shale, located in East Texas and Northern Louisiana. Our operations are concentrated primarily in Desoto Parish, Louisiana in the Holly Field. We currently have 38,224 net (57,502 gross) acres in this area. As of December 31, 2014, we have identified 197 drilling locations.

During 2014, we invested $8 million in capital expenditures in our Haynesville Shale program. For the quarter ended March 31, 2015, our average net daily production was 76 MMcfe/d. As of March 31, 2015, we had 106 net producing wells. In 2012, we suspended investment in the Haynesville program due to low natural gas prices. In 2015, we have allocated a portion of our capital budget to our Haynesville drilling program based on its returns in the forecasted price environment. Our acreage in the Haynesville Shale is held-by-production.

The following table provides a summary of acreage and inventory data as of December 31, 2014:

(1)                                 Our inventory as of December 31, 2014 does not include the following potential additional locations:

·                  In the Wolfcamp Shale area, (i) horizontal drilling locations in the Cline Shale and (ii) vertical drilling locations in the Spraberry and other stacked formations; and

·                  In Altamont, (i) additional vertical infill locations and (ii) horizontal drilling locations in the Wasatch and Green River formations.

(2)                                 Represents gross operated wells completed in 2014.

(3)                                 Calculated as Drilling Locations divided by 2014 Drilling Locations. At 2015 activity levels, inventory is approximately 30 years.

The following table provides 5-year well inventory economics:

(1)                                 Pre-Tax IRR is the annual effective compounded rate of return before taxes, which assumes $65 per Bbl WTI pricing and $3.50 per MMBtu Henry Hub pricing.

(2)                                 Break-even oil price (WTI) required to generate a 10% pre-tax IRR using most current well costs and current type curve. Wolfcamp incorporates early time performance while holding EUR’s flat.

(3)                                 Recent improvements in Wolfcamp well performance have lowered the break-even price to approximately $44.00/Bbl.

We have used the data from our development programs to identify and prioritize our inventory. These drilling locations are only included in our inventory after they have been evaluated technically.

Business Strategy

We are a growth-oriented, 100% onshore, oil-weighted company with a large inventory of low-risk dirlling locations. We are focused on creating value by implementing the following strategies:

Grow Production, Cash Flow and Reserves through the Development of our Extensive Drilling Inventory

We have assembled a drilling inventory of 5,673 drilling locations, (including 979 drilling locations to which we have attributed proved undeveloped reserves as of December 31, 2014, of which approximately 92% are oil wells) and across approximately 476,876 net (647,479 gross) acres in the Eagle Ford Shale, the Wolfcamp Shale, Altamont and the Haynesville Shale. The concentration and scale of our leasehold positions, coupled with our technical understanding of the reservoirs, should allow us to efficiently develop our operating areas and allocate capital to maximize the value of our resource base. In 2014, we invested $2.2 billion (99% in our oil areas) of capital expenditures and grew continuing oil production by 19,000 Bbls/d, or 51%, from an average of 36,000 Bbls/d in 2013 to an average of 55,000 Bbls/d in 2014. We also increased proved oil reserves by 29.3 MMBbls, or 10%, from 291.5 MMBbls at December 31, 2013 to 320.8 MMBbls at December 31, 2014. In 2015, we plan to invest approximately $1.2 billion to $1.25 billion of capital expenditures, allocated primarily to our oil programs. We believe that our extensive inventory of low-risk drilling locations, combined with our operating expertise, will enable us to continue to deliver production, cash flow and reserve growth and create value. We consider our inventory of drilling locations to be low-risk because they are in areas where we (and other producers) have extensive drilling and production experience and success.

Maintain an Extensive Low-Risk Drilling Inventory

We have a demonstrated track record of identifying and cost effectively acquiring low-risk resource development opportunities. We follow a geologically driven strategy to establish large, contiguous leasehold positions in the core of prolific basins and opportunistically add to those positions through acquisitions over time. We were an early entrant into the Eagle Ford and Wolfcamp shales through grassroots leasing efforts, amassing average positions of over 100,000 net acres, and we methodically expanded our positions in Altamont and Wolfcamp through targeted acquisitions. We will continue to identify and opportunistically acquire additional acreage and producing assets to add to our multi-year drilling inventory.

Enhance Returns by Continuously Improving Capital and Operating Efficiencies

We maintain a disciplined, returns-focused approach to capital allocation. Our large and diverse portfolio of drilling locations allows us to conduct cost-efficient operations and allocate capital to our highest-margin assets in a variety of commodity price environments. We continuously monitor and adjust our development program in order to maximize the value of our extensive portfolio of drilling opportunities. In each of our operating areas, we have realized improvements in EURs while delivering reductions in drilling and completion costs since 2011. These cost reductions have been due to many improvements, including substantial reductions in cycle times and successful negotiations for supplies and services. We will look to gain further cost reductions going forward from additional learning and efficiencies, including drilling wells from common pad sites, shared use of pre-existing central facilities and other economies of scale.

Identify and Develop Additional Drilling Opportunities in our Portfolio

Our existing asset base provides numerous opportunities for our highly experienced technical team to create value by increasing our inventory beyond our currently identified drilling locations. In the Permian Basin, we have evaluated multiple Wolfcamp horizons, and have drilled at the locations of our initial results in the Wolfcamp A horizon. Additionally, this acreage is prospective for the Cline Shale, the Spraberry and other stacked formations. We believe Altamont has a significant inventory of low-risk, vertical infill drilling locations. Altamont is also currently being assessed for 80-acre vertical infill programs in the Wasatch and Green River formations and additional horizontal development potential in multiple shale and tight sands intervals. Our 3-D seismic programs in the Uinta and Permian Basins should further enhance our ability to increase the number of and high grade our drilling locations.

Maintain Liquidity and Financial Flexibility

We intend to fund our organic growth predominantly with internally generated cash flows while maintaining ample liquidity. We will continue to maintain a disciplined approach to spending whereby we allocate capital in order to optimize

returns and create value. As of March 31, 2015, after giving effect to the Refinancing Transactions (as defined herein), we had approximately $1.7 billion available to borrow under the RBL facility (after giving effect to issued and undrawn letters of credit).  As we pursue our strategy of developing high-return opportunities in our operating areas, we expect our cash flow and borrowing base to grow, thereby further enhancing our liquidity and financial strength.

Competitive Strengths

We believe the following strengths provide us with significant competitive advantages:

Large, Concentrated Operated Positions in the Core Areas of Prolific Oil Resource Plays

We own and operate contiguous leasehold positions in the core areas of three of the premier North American oil resource plays: the Eagle Ford Shale, the Wolfcamp Shale and Altamont. We have approximately 438,651 net (589,977 gross) acres across these three plays that we have substantially de-risked through our ongoing drilling programs. We view this acreage as de-risked because the drilling locations were selected based on our extensive delineation drilling and production history in the area and well-established industry activity surrounding our acreage. Based on our analysis of subsurface data and the production history of our wells and those of offset operators, we have confirmed high quality reservoir characteristics across a broad aerial extent with significant hydrocarbon resources in place. Based upon our well costs and production rates, we believe our oil areas offer some of the best single well rates of return of all North American resource plays.

Multi-Year Inventory of Low-Risk Drilling Opportunities

Our approximately 5,670 low-risk drilling locations across our operating areas provide us with approximately 21 years of drilling inventory (more than 30 years of drilling inventory at 2015 activity levels), of which 92% are oil wells. We have used the subsurface data from our development programs to identify and prioritize our inventory. These drilling locations are included in our inventory after they have passed through a rigorous technical evaluation. In addition to our approximately 5,670 identified drilling locations, we believe we have the potential to increase our multi-year drilling inventory with horizontal drilling locations in the Cline Shale and vertical drilling locations in the Spraberry and other stacked formations in the Permian Basin, and vertical infill and horizontal drilling locations in the Wasatch and Green River formations in Altamont. Our ongoing technical assessment and development activities provide the potential for identification of additional drilling opportunities on our properties. A portion of this acreage is also prospective for the Cline Shale. In Altamont, we have potential for additional vertical infill drilling locations.

High-Quality Proved Reserve Base with Substantial Current Production

Our leasehold position and inventory of low-risk drilling locations is complemented by a substantial proved reserve base. As of December 31, 2014, we had proved reserves of 622.2 MMBoe (52% oil and 67% liquids). For the quarter ended March 31, 2014, our average production was 102,421 Boe/d, which was 59% oil and 70% liquids. Our current production provides a stable source of cash flow to fund the development of our operating areas. This significantly reduces our reliance on outside sources of capital. In addition, our extensive inventory improves our ability to replace and grow proved reserves.

Significant Operational Control with Low Cost Operations

Our significant operational control permits us to efficiently manage the amount and timing of our capital outflows, allowing us to continually improve our drilling and operating practices. We operate over 85% of our producing wells and have operational control of approximately 97% of our drilling inventory as of December 31, 2014. We employ a centralized drilling and completion structure to accelerate our internal knowledge transfer around the execution of our drilling and completion programs.

Capital Allocation Flexibility and Scale across Multiple Basins

Our existing assets are geographically diversified among many of the major basins of North America, which helps to insulate us from regional commodity pricing and cost dislocations that occur from time to time. While our existing producing assets are well diversified, they are also of a critical mass which enables us to drive efficiencies and benefit from economies of scale across multiple basins. Furthermore, because of our centralized operational structure, we are able to quickly transfer operational efficiencies from one project to the next. From this deep operational knowledge base and sizeable, concentrated

positions in multiple basins, we have the flexibility to allocate significant amounts of capital across our properties in an efficient and value-maximizing manner.

Ability to Direct Capital to the Prolific Haynesville Shale

The Haynesville Shale is a key asset for us and is likely to compete for development capital if natural gas prices improve. Because our operations are surrounded by existing infrastructure, future returns are primarily driven by drilling and completion costs and natural gas prices. Since our Haynesville wells have demonstrated high initial production rates and strong EURs, small movements in natural gas prices can drive significant incremental value creation. Since these leases are held-by-production, we have the ability to redirect capital to this prolific asset and have allocated a portion of our capital budget in 2015 to our Haynesville drilling program based on its returns in the forecasted commodity price environment.

Significant Liquidity and Financial Flexibility

As of March 31, 2015, after giving effect to the Refinancing Transactions, we had approximately $1.7 billion available to borrow under the RBL facility (after giving effect to issued and undrawn letters of credit).  We maintain a robust hedging program in order to protect our cash flows through commodity cycles. Based on our hedges in place as of March 31, 2015, we were approximately 96% hedged (based on the midpoint of our 2015 production guidance) at a weighted average price of $91.16 per barrel for the remainder of 2015. We have (i) fixed price hedges on approximately 96% of and 82% of our oil production, at weighted average floor prices of $91.16 and $80.29 in 2015 and 2016, respectively (based on the midpoint of 2015 production guidance) and (ii) hedged basis risk on approximately 50% of our year-to-date Eagle Ford oil production. After the completion of this offering, we expect that liquidity provided by operating cash flow, availability under the RBL Facility and available cash will give us the financial flexibility to pursue our planned capital expenditures in 2015 and for the foreseeable future.

Experienced Management Team

With an average of 25 years of experience, our senior management team has built a track record at El Paso Corporation and in former leadership roles with Burlington Resources, ConocoPhillips and other leading energy companies. The majority of our senior management team has worked together for over a decade and has significant experience in identifying, acquiring and developing unconventional oil and natural gas assets, including experience in horizontal drilling and developing shales. Through a combination of invested equity and incentive programs, we believe our management is motivated to deliver high returns, create value and maintain safe and reliable operations.

2015 Capital Budget

For 2015, we expect our total capital budget will be approximately $1.2 billion to $1.25 billion. Our capital program will remain focused on continuing to grow production, cash flows, and reserves in our highest return oil programs. In particular, the Eagle Ford Shale currently generates the highest returns in our portfolio and, as a result we are investing the majority of our capital in this program. We expect that liquidity provided by operating cash flow, availability under the RBL Facility and available cash will be sufficient to fund the 2015 capital plan.

Our 2015 capital expenditures of approximately $1.2 billion to $1.25 billion are allocated primarily to our oil programs: $825 million for Eagle Ford, $190 million for Wolfcamp, $140 million for Altamont and $100 million for Haynesville. We expect well completions between 160-190. For the year ended December 31, 2014, our capital expenditures were approximately $2.2 billion (including approximately $158 million of acquisition capital), and we completed 273 gross wells.

Recent Events

Operational Update

As of March 31, 2015, our capital and operating costs have decreased significantly since the third quarter of 2014, during which time we have realized a 20% reduction in gross well costs. In addition our adjusted unit cash operating costs have decreased 15% from the first quarter of 2014.

In our Wolfcamp program, we continue to realize improved production performance from increased target zone accuracy, improved lateral placement, reduced cycle time, and completion optimization. As of April 30, 2015, the most recently completed 18 wells in our Wolfcamp program produced 68% more oil than our current type curve after 120 days.

In our Eagle Ford program improved landing zone accuracy, drilling cycle time improvements, and completion optimization have also resulted in improved production performance. As of April 30, 2015, the most recently completed 39 wells in our Eagle Ford program produced 14% more oil than our current type curve after 90 days.

Tender Offer

On May 19, 2015, we commenced a cash tender offer (the “Tender Offer”) for any and all of the $750 million aggregate principal amount outstanding of our 6.875% Senior Secured Notes due 2019 (the “2019 Senior Secured Notes”). Under the terms of the Tender Offer, we are offering to repurchase the 2019 Senior Secured Notes for cash in an amount of $1,037.88 per $1,000 principal amount of the 2019 Senior Secured Notes, together with accrued and unpaid interest up to, but not including, the settlement date. This represents a tender premium of $37.88 per $1,000 principal amount of 2019 Senior Secured Notes for holders that tender on or prior to 5:00 p.m. New York City time on May 27, 2015 (the “Expiration Time”). Upon completion of the Tender Offer, we intend to redeem any 2019 Senior Secured Notes that have not been tendered or accepted for payment. The Tender Offer will expire at the Expiration Time, unless extended. The Tender Offer is conditioned upon, among other things, the closing of this Offering, but this offering is not conditioned upon closing of the Tender Offer. Nothing in this offering memorandum should be construed as an offer to purchase any outstanding 2019 Senior Secured Notes, as the Tender Offer is being made only to the recipients of an Offer to Purchase dated May 19, 2015, upon the terms and subject to the conditions set forth therein.

As used in this offering memorandum, the term “Refinancing Transactions” refers collectively to the offering of the notes and the use of the net proceeds therefrom as described under “Use of Proceeds.”

Corporate Structure

The diagram below sets forth a simplified version of our current organizational structure and our principal indebtedness as of March 31, 2015 after giving pro forma effect to the Refinancing Transactions. The diagram is provided for illustrative purposes only and does not represent all legal entities affiliated with, or all obligations of the Issuer and their subsidiaries.

(1)                                 EPE Acquisition, LLC has made a non-recourse pledge of the equity of the Issuer to secure the RBL Facility.

(2)                                 As of March 31, 2015, approximately $980 million was drawn and outstanding under the RBL Facility. See “Capitalization” and “Description of Other Indebtedness” for more information regarding borrowings, borrowing base and availability under the RBL Facility.

(3)                                 All operating subsidiaries of the Issuer guarantee and pledge certain assets under the RBL Facility and the senior secured term loans. These subsidiaries also guarantee our existing senior notes on a senior unsecured basis and will guarantee these notes.

Summary Pro Forma Operating and Reserve Information

Proved Reserves

The following table summarizes our estimated net proved reserves and related PV-10 and standardized measure of discounted future net cash flows as of December 31, 2014. The proved reserves as of December 31, 2014 are based on our internal reserve report. The reserve data represents only estimates, which are often different from the quantities of oil and natural gas that are ultimately recovered. The risks and uncertainties associated with estimating proved oil and natural gas reserves are discussed further in “Risk Factors.” Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at December 31, 2014. You should refer to the information included under the headings “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business” appearing elsewhere in this offering memorandum and incorporated herein by reference in evaluating the material presented below. The information in the following table does not give any effect to or reflect our commodity hedges.

Ryder Scott conducted an audit of the estimates of the proved reserves that we prepared as of December 31, 2014 and concluded that the overall procedures and methodologies we utilized in preparing these estimates complied with current SEC regulations and the overall proved reserves for the reviewed properties as estimated by us are, in aggregate, reasonable within the established audit tolerance guidelines of 10% as set forth in the Society of Petroleum Engineers (“SPE”) auditing standards.

(1)                                 PV-10 is a non-GAAP measure and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. Our PV-10 differs from our standardized measure because our standardized measure reflects discounted future income taxes related to our domestic operations. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the relative monetary significance of our oil, natural gas and NGLs properties regardless of tax structure. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil, natural gas and NGLs properties. PV-10, however, is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil (including NGLs) and natural gas reserves. The unweighted arithmetic average of the historical first-day-of-the-month prices for the prior 12 months was $94.99 per barrel of oil (WTI) and $4.34 per MMBtu of natural gas (Henry Hub) as of December 31, 2014.

The following table provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows (in millions):

Production, Revenues and Price History

The following table sets forth information regarding net production and certain price and cost information for each of the periods indicated.

(1)                                 The years ended 2013 and 2012 do not include volumes from our approximate 49% equity interest in the volumes of Four Star Oil & Gas Company (Four Star), which we sold in September 2013. The year ended December 31, 2012 does not include volumes from our South Louisiana Wilcox and Arklatex Tight Gas areas sold in 2014, our CBM, South Texas, and the majority of our Arklatex assets, all of which were sold in 2013, and our Gulf of Mexico assets, which were sold in 2012. For periods after May 24, 2012, our South Louisiana Wilcox, CBM, South Texas and Arklatex assets are treated as discontinued operations and accordingly volumes related to those assets are excluded from all financial and non-financial metrics.

(2)                                 Amounts reflect settlements on derivative instruments, including cash premiums. No cash premiums were received for the quarter ended March 31, 2015. Cash premiums received for the quarter ended March 31, 2014 were less than $1 million. For the year ended December 31, 2014 we received cash premiums of approximately $1 million, for the year ended December 31, 2013 we received cash premiums of $9 million and for the year ended December 31, 2012 we paid $3 million of cash premiums.

(3)                                 Total adjusted cash operating costs per unit for each period were $11.41/Boe, $13.45/Boe, $13.26/Boe, $13.17/Boe and $10.26/Boe. Adjusted cash operating cost is a non-GAAP measure. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Cash Operating Costs and Adjusted Cash Operating Costs” incorporated herein by reference for a reconciliation of this measure to operating expenses, the most directly comparable GAAP measure.

(4)                                Production taxes include ad valorem and severance taxes.

(5)                                 Recorded in conjunction with early rig termination fees.