Obligation Everest Peak Finance 9.375% ( US29977HAB69 ) en USD

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US29977HAB69 ( en USD )

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Prospectus brochure de l'obligation Everest Acquisition Finance US29977HAB69 en USD 9.375%, échue

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Everest Acquisition Finance est une société de capital-investissement spécialisée dans le financement d'acquisitions et de croissance pour les entreprises du marché intermédiaire.

L'Obligation émise par Everest Peak Finance ( Etats-unis ) , en USD, avec le code ISIN US29977HAB69, paye un coupon de 9.375% par an.
Le paiement des coupons est semestriel et la maturité de l'Obligation est le 01/05/2020

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TABLE OF CONTENTS
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Filed pursuant to Rule 424(b)(3)
Registration No. 333-183815
PROSPECTUS
EP Energy LLC
Everest Acquisition Finance Inc.
Exchange Offer for
$750,000,000 6.875% Senior Secured Notes due 2019
$2,000,000,000 9.375% Senior Notes due 2020 and
$350,000,000 7.750% Senior Notes due 2022
The Notes and the Guarantees
·
We are offering to exchange $750,000,000 of our outstanding 6.875% Senior Secured Notes due 2019 and certain related guarantees, which we refer to col ectively as
the "initial senior secured notes," for a like aggregate amount of our registered 6.875% Senior Secured Notes due 2019 and certain related guarantees, which we refer to
col ectively as the "senior secured exchange notes." The senior secured exchange notes wil be issued under an indenture dated as of April 24, 2012. We refer to the
initial senior secured notes and the senior secured exchange notes col ectively as the "senior secured notes."
·
We are offering to exchange $2,000,000,000 of our outstanding 9.375% Senior Notes due 2020 and certain related guarantees, which we refer to col ectively as the
"initial 2020 senior notes," for a like aggregate amount of our registered 9.375% Senior Notes due 2020 and certain related guarantees, which we refer to col ectively as
the "senior 2020 exchange notes." The senior 2020 exchange notes wil be issued under an indenture dated as of April 24, 2012. We refer to the initial 2020 senior notes
and the senior 2020 exchange notes col ectively as the "senior 2020 notes."
·
We are offering to exchange $350,000,000 of our outstanding 7.750% Senior Notes due 2022 and certain related guarantees, which we refer to col ectively as the "initial
2022 senior notes," for a like aggregate amount of our registered 7.750% Senior Notes due 2022 and certain related guarantees, which we refer to col ectively as the
"senior 2022 exchange notes." The senior 2022 exchange notes wil be issued under an indenture dated as of August 13, 2012. We refer to the initial 2022 senior notes
and the senior 2022 exchange notes col ectively as the "senior 2022 notes."
·
We refer to the senior 2020 notes and the senior 2022 notes col ectively or individual y, as the context requires, as the "senior notes."
·
We refer to the initial senior secured notes, the initial 2020 senior notes and the initial 2022 senior notes col ectively or individual y, as the context requires, as the "initial
notes." We refer to the senior secured exchange notes, the senior 2020 exchange notes and the senior 2022 exchange notes col ectively or individual y, as the context
requires, as the "exchange notes." We refer to the initial notes and the exchange notes col ectively as the "notes."
·
The senior secured exchange notes will mature on May 1, 2019. We will pay interest on the senior secured exchange notes semi-annual y on May 1 and November 1 of
each year, commencing on November 1, 2012, at a rate of 6.875% per annum, to holders of record on the April 15 or October 15 immediately preceding the interest
payment date.
·
The senior 2020 exchange notes wil mature on May 1, 2020. We wil pay interest on the senior 2020 exchange notes semi-annual y on May 1 and November 1 of each
year, commencing on November 1, 2012, at a rate of 9.375% per annum, to holders of record on the April 15 or October 15 immediately preceding the interest payment
date.
·
The senior 2022 exchange notes wil mature on September 1, 2022. We wil pay interest on the senior 2022 exchange notes semi-annual y on March 1 and September 1
of each year, commencing on March 1, 2013, at a rate of 7.750% per annum, to holders of record on the February 15 or August 15 immediately preceding the interest
payment date.
·
The exchange notes will be guaranteed, jointly and severally, by our present and future direct or indirect wholly owned material domestic subsidiaries that guarantee our
new senior secured reserve-based revolving credit facility (the "RBL Facility").
·
The senior secured exchange notes and the related guarantees wil be secured (i) on a first-priority basis by a perfected pledge of the capital stock of all first-tier foreign
subsidiaries of EP Energy LLC (the "Issuer"), Everest Acquisition Finance Inc. (the "Co-Issuer" and, together with the Issuer, the "Issuers") and each of the guarantors
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(which pledge wil be limited to 65% of the voting capital stock and 100% of the non-voting capital stock of each such subsidiary) (the "Secured Notes/Term Loan
Priority Col ateral"); and (i ) on a second-priority basis by al of the other assets securing the RBL Facility (including a perfected pledge of al of the capital stock of each
direct, whol y owned, domestic, material restricted subsidiary of each of the Issuers and the guarantors), subject to exceptions described herein.
Terms of the Exchange Offer
·
The exchange offer will expire at 5:00 p.m., New York City time, on November 27, 2012, unless we extend it.
·
If al the conditions to this exchange offer are satisfied, we wil exchange al of our initial notes that are validly tendered and not withdrawn for the exchange notes.
·
You may withdraw your tender of initial notes at any time before the expiration of this exchange offer.
·
The exchange notes that we wil issue you in exchange for your initial notes wil be substantial y identical to your initial notes except that, unlike your initial notes, the
exchange notes will have no transfer restrictions or registration rights.
·
The exchange notes that we wil issue you in exchange for your initial notes are new securities with no established market for trading.
Before participating in this exchange offer, please refer to the section in this prospectus entitled "Risk Factors" beginning on
page 34.
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this
prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
We have not applied, and do not intend to apply, for listing the notes on any national securities exchange or automated quotation system.
Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer must acknowledge that it wil deliver a prospectus in connection with any resale
of those exchange notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer wil not be deemed to admit that it is an "underwriter"
within the meaning of the Securities Act of 1933, as amended (the "Securities Act"). This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-
dealer in connection with resales of exchange notes received in exchange for initial notes where those initial notes were acquired by that broker-dealer as a result of market-making activities
or other trading activities. We have agreed that, for a period of 180 days after the expiration date, we wil make this prospectus available to any broker-dealer for use in connection with any
such resale. See "Plan of Distribution."
The date of this prospectus is October 22, 2012.
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Table of Contents
TABLE OF CONTENTS

Page

Summary

1

Risk Factors

34

Market and Industry Data and Forecast

73

Cautionary Statements Concerning Forward-Looking Statements

74

Use of Proceeds

75

Capitalization

76

Unaudited Pro Forma Condensed Consolidated Financial Data

77

Selected Historical Consolidated Financial Data

83

Management's Discussion and Analysis of Financial Condition and Results of Operations

86

Business
112

Management
139

Security Ownership of Certain Beneficial Owners and Management
166

Certain Relationships and Related Party Transactions
168

Description of Other Indebtedness
170

The Exchange Offer
174

Description of Senior Secured Exchange Notes
185

Description of Senior 2020 Exchange Notes
271

Description of Senior 2022 Exchange Notes
341

Book-Entry; Delivery and Form
411

Certain U.S. Federal Income Tax Considerations
413

Plan of Distribution
420

Legal Matters
421

Experts
421

Glossary of Oil and Natural Gas Terms
A-1

Index to Consolidated Financial Statements
F-1
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PRESENTATION OF FINANCIAL INFORMATION
EP Energy LLC (the "Issuer" and "Successor" and formerly known as Everest Acquisition LLC) was formed as a Delaware limited
liability company on March 23, 2012 by Apollo Global Management LLC (Apollo) and other private equity investors (collectively, the
Sponsors). On May 24, 2012, the Sponsors acquired EP Energy Global LLC, (the "Predecessor" and formerly known as EP Energy
Corporation and EP Energy, L.L.C. after its conversion into a Delaware limited liability company) and subsidiaries for approximately
$7.2 billion in cash as contemplated by the merger agreement among El Paso Corporation ("El Paso") and Kinder Morgan, Inc. ("KMI").
The entities acquired are engaged in the exploration for and the acquisition, development, and production of oil, natural gas and NGL
primarily in the United States, with other international activities in Brazil and Egypt (Egypt was sold in June 2012) and together constituted
the oil and natural gas operations of El Paso.
We present historical financial information prior to May 24, 2012, relating to EP Energy Global LLC and its consolidated subsidiaries
in this prospectus. Following the acquisition, EP Energy Global LLC is a wholly owned subsidiary of the Issuer and is the predecessor of
the Issuer for accounting purposes. Accordingly, its financial statements are presented for the historical periods prior to the Acquisition
Transactions (as defined herein). The Issuer conducts all of its operations through EP Energy Global LLC and other subsidiaries that were
subsidiaries of EP Energy Global LLC at the time of the historical financial statements presented in this prospectus and that were spun out of
EP Energy Global LLC prior to the closing of the Acquisition Transactions.
Historical financial results in this prospectus for the periods before and after the Acquisition on May 24, 2012, have been presented
separately for the predecessor and successor in accordance with required GAAP presentation. Despite this separate GAAP presentation, the
successor had no independent oil and gas operations prior to the acquisition and accordingly there were no operational exploration and
production activities changed as a result of the acquisition of the Predecessor. Consequently, given the continuity of operations, when
assessing certain sections in our Management's Discussion and Analysis (e.g. variance analysis, operating statistics) and pro forma
financial information for the periods presented throughout this prospectus, we have presented a combined analysis of the pre-acquisition
results of operations of the Predecessor and the post-acquisition results of operations of the Successor. We believe that reflecting this
combined information and analysis, while non-GAAP, facilitates the most meaningful comparison and understanding of our operating
performance in 2012 over the same period in the prior year and the pro forma results of our operations.
USE OF NON-GAAP FINANCIAL INFORMATION
We use the non-GAAP financial measures of Reported EBITDA, Adjusted EBITDAX, Cash Operating Costs /Adjusted Cash Operating
Costs, Reserve Replacement Costs / Reserve Replacement Ratio, and PV-10. We believe these are supplemental measures and provide
meaningful information to our investors; however, due to the limitations of these measures as analytical tools, we rely primarily on our
GAAP results. Each of these non-GAAP measures is further described below or as further noted.
Reported EBITDA and Adjusted EBITDAX. Reported EBITDA is defined as net income plus interest and debt expense, income taxes
and depreciation, depletion and amortization. Adjusted EBITDAX is defined as Reported EBITDA, adjusted as applicable in the relevant
period, for the net change in the fair value of derivatives (mark to market effects, net of cash settlements and premiums related to these
derivatives), ceiling test charges or other impairments, adjustments to reflect cash distributions of the earnings from our unconsolidated
affiliates, non-cash equity based compensation expenses, transition and restructuring costs we expect not to recur, advisory fees paid to our
sponsors and exploration expenses.
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We believe that the presentation of Reported EBITDA and Adjusted EBITDAX is important to provide management and investors with
(i) additional information to evaluate our ability to service debt adjusting for items required or permitted in calculating covenant
compliance under our debt agreements, (ii) an important supplemental indicator of the operational performance of our business, (iii) an
additional criterion for evaluating our performance relative to our peers, (iv) additional information to measure our liquidity (before cash
capital requirements and working capital needs) (v) and supplemental information to investors about certain material non-cash and/or other
items that may not continue at the same level in the future.
Reported EBITDA and Adjusted EBITDAX have limitations as analytical tools and should not be considered in isolation or as a
substitute for analysis of our results as reported under U.S. GAAP or as an alternative to net income, operating income, net cash provided by
operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. For example, our
presentation of Reported EBITDA and Adjusted EBITDAX may not be comparable to similarly titled measures used by other companies in
our industry. Furthermore, our presentation of Reported EBITDA and Adjusted EBITDAX should not be construed as an inference that our
future results will be unaffected by the items noted above or what we believe to be other unusual or non-recurring items or that in the future
we may not incur expenses that are the same as or similar to some of the adjustments in this presentation.
Cash Operating Costs / Adjusted Cash Operating Costs. We monitor cash operating costs required to produce our oil and natural
gas production volumes. Cash operating costs is a non-GAAP measure calculated on a per Mcfe basis and includes total operating expenses
less depreciation, depletion and amortization expense, ceiling test and other impairment charges, exploration expense, and transportation
costs and costs of products. Adjusted cash operating costs reflects cash operating costs adjusted for non-recurring transition and
restructuring costs, advisory fees paid to our sponsors and non-cash equity based compensation expense. We believe cash operating costs
and adjusted cash operating costs per unit are valuable measures to provide management and investors reflecting operating performance and
efficiency; however, these measures may not be comparable to similarly titled measures used by other companies and are subject to several
of the same limitations as analytical tools as noted in the paragraphs above.
Reserve Replacement Ratio/Reserve Replacement Costs. We calculate two primary metrics, (i) a reserve replacement ratio and
(ii) reserve replacement costs, to measure our ability to establish a long-term trend of adding reserves at a reasonable cost in our key asset
areas. The reserve replacement ratio is an indicator of our ability to replenish annual production volumes and grow our reserves. It is
important for us to economically find and develop new reserves that will more than offset produced volumes and provide for future
production given the inherent decline of hydrocarbon reserves. In addition, we calculate reserve replacement costs to assess the cost of
adding reserves, which is ultimately included in depreciation, depletion and amortization expense. For a further discussion of these
measures, see "Management's Discussion and Analysis of Financial Condition and Results of Operations."
PV-10. PV-10 is considered a non-GAAP measure and is derived from the standardized measure of discounted future net cash flows
of our oil and natural gas properties, 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 taxes, discounted at 10%. We believe that the
presentation of PV-10 is relevant and useful to investors because it presents the relative monetary significance of our oil and natural gas
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 and natural gas
properties. PV-10, however, is not a substitute for the standardized measure of
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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, natural gas and NGL reserves.
PRESENTATION OF RESERVES INFORMATION
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only estimated proved, probable and possible
reserves that meet the SEC's definitions of such terms. We disclose estimated proved reserves in this prospectus. Our estimates of proved
reserves contained in this prospectus were estimated by our internal staff of engineers and comply with the rules and definitions
promulgated by the SEC. For the year ended December 31, 2011, we engaged Ryder Scott Company, L.P., an independent petroleum
engineering firm, to perform reserve audit services with respect to a substantial portion of our proved reserves.
EQUIVALENCY
This prospectus presents certain production and reserves-related information on an "equivalency" basis. Equivalent volumes are
computed with oil and natural gas liquids quantities converted to Mcfe at a ratio of one Bbl to six Mcf, and natural gas converted to Boe at a
ratio of six Mcf to one Bbl. These conversions are based on energy equivalency conversion methods primarily applicable at the burner tip
and do not represent value equivalencies at the wellhead. Although these conversion factors are industry accepted norms, they are not
reflective of price or market value differentials between product types.
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SUMMARY
This summary highlights information appearing elsewhere in this prospectus. This summary is not complete and does not contain
all of the information that may be important to you. You should carefully read the entire prospectus, including the information presente
under "Risk Factors" and "Unaudited Pro Forma Condensed Consolidated Financial Data" and the historical financial statements and
related notes presented elsewhere in this prospectus.
Unless otherwise indicated or the context otherwise requires, references in this prospectus to "we," "our," "us," and the
"Company" refer to EP Energy LLC (formerly known as Everest Acquisition LLC) (the "Issuer") and each of its consolidated
subsidiaries, including Everest Acquisition Finance Inc. (the "Co-Issuer" and, together with the Issuer, the "Issuers"). References in th
prospectus to the "Sponsors" refer to the entities described under "--Our Sponsors" and their respective affiliates. You should carefully
consider all information in this prospectus, including the matters discussed in "Risk Factors." Financial information identified in this
prospectus as "pro forma" gives effect to the closing of the Acquisition and Refinancing Transactions, which are described in this
prospectus summary under "--The Acquisition Transactions" and "--The Refinancing Transactions." Certain oil and gas industry term
used in this prospectus are defined in the "Glossary of Oil and Natural Gas Terms" beginning on page A-1 of this prospectus.
Our Company
We are one of North America's leading independent oil and natural gas producers. We have a large and diverse base of producing
assets that provides cash flow to fund the development of our key programs, which at this time are primarily oil-focused. Over the last
several years, we have high-graded our future drilling inventory by establishing large acreage positions with repeatable drilling
opportunities and more favorable return characteristics. Domestically, we currently operate through three divisions: Central, Eagle Ford an
Southern, and have a strategic presence in well-known oil resource areas, including the Eagle Ford Shale, the Altamont Field, the Wolfcam
Shale and the South Louisiana Wilcox area. Our large and diverse producing gas assets include our Haynesville Shale position, substantiall
all of which is held by production, which gives us a significant presence in unconventional natural gas. We also have a small international
presence in Brazil.
Our management team, which has been with us since at least 2007, has an average of 22 years of experience in the oil and gas industry
and technical and operating expertise across our geographic regions. Our management team has a track record of identifying, acquiring and
developing low-risk, repeatable resource opportunities and has executed a multi-year effort to add assets that fit our competencies. Today,
our substantial key program drilling inventory encompasses approximately 4,500 locations and more than 20 years of drilling activity at our
current pace. We have operational control over approximately 77% of our producing wells and 88% of our key program drilling inventory
as of December 31, 2011. This control has allowed us to continually improve our capital and operating efficiencies. In 2011, we drilled 23
gross wells domestically (182 net to our ownership interests ("net")) with a success rate of 100%, adding approximately 1,100 Bcfe of
proved reserves at a replacement cost of $1.43 per Mcfe, the majority of which was oil.
As of December 31, 2011, we had proved reserves of approximately 4.0 Tcfe with a pre-tax PV-10 of approximately $7 billion (of
which approximately 54% of the PV-10 was attributed to proved developed producing reserves). We had 182 MMBbls of proved oil
reserves, 19 MMBbls of proved NGL reserves and 2,782 Bcfe of proved natural gas reserves, representing 27%, 3% and 70%,
respectively, of our total proved reserves. Given the recent commodity price environment, we have shifted our focus primarily to
developing our key oil programs, resulting in 48% of our revenues (excluding realized and unrealized gains on financial derivatives) being
contributed by oil and NGLs in the fourth quarter of 2011, versus 34% in the fourth quarter of 2010. Our oil production for the month

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of December 2011 was approximately 24,000 Bbls/d, which contributed to our approximate 50% year-over-year growth in oil production
for the fourth quarter of 2011. We anticipate that approximately 91% of our capital expenditures for 2012 will be allocated to oil-focused
key programs. For the six month period ended June 30, 2012, 57% of our revenues (excluding realized and unrealized gains on financial
derivatives) were contributed by oil and NGLs, versus 35% during the same period in 2011. For the month of June 2012, our oil production
was approximately 27,000 Bbls/d.
For the six months ended June 30, 2012, on a pro forma basis after giving effect to the Acquisition Transactions and the Refinancing
Transactions, we generated Adjusted EBITDAX of $655 million on average daily production of 906 MMcfe/d. See "--Summary Historica
and Pro Forma Consolidated Financial and Other Operating Data" for our definition of Adjusted EBITDAX and a reconciliation of Adjuste
EBITDAX to amounts reported under GAAP.
The following table provides summary data for each of our areas of operation:
As of

As of December 31, 2011
June 30, 2012
Average
Proved
Daily
Reserves
% Proved
Production

(Bcfe)
Developed
PV-10

Net Acres

(MMcfe/d)

(dollars in millions)

United States

Central

Haynesville
Shale

903
34%$
719 41,000
317
South
Louisiana
Wilcox

31
48 143 183,000
16
Altamont
Field

551
37 1,479 176,000
62
Other
Central
1,117
75 998 1,339,000
208
Eagle Ford

Eagle
Ford
Shale

642
18 2,283 157,000
91
Southern

Wolfcamp
Shale

148
12 337 138,000
10
Other
Southern(1)

326
94 536 314,000
110

Total
United
States
3,718
48 6,495 2,348,000
814
International

Brazil

95
100 210 132,000
36
Egypt(2)

--
--
-- 774,000
--

Total
Consolidated
3,813
50 6,705 3,254,000
850

Unconsolidated Affiliate(3)

174
86 311

56

Total
Combined
3,987
51 $ 7,016

906

(1)
Gulf of Mexico assets were sold in July 2012 and comprised reserves of 90 Bcfe, PV-10 of $150 million, net acres o
233,000 and average daily production of 45 Mcfe/d.
(2)
Sold in June 2012.
(3)
Represents our approximate 49% equity interest in Four Star Oil & Gas Company ("Four Star").
Key Programs
Over the past five years, our strategy has been to focus on areas that offer repeatable drilling programs, enabling us to reduce
development costs, and to grow our asset base and inventory size. We have consistently improved the quality and increased the number of
our drilling opportunities. During 2011, our principal focus was in the Haynesville Shale, the Eagle Ford Shale, the Wolfcamp Shale, the

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Altamont Field and South Louisiana Wilcox. We are redeploying the capital allocated to the Haynesville Shale to our oil programs. The
technical and operating experience gained from our successful Haynesville program has been employed in our other key programs, includin
the Eagle Ford Shale.
Haynesville Shale
The initial execution of our strategy of repeatable drilling programs was in the Haynesville Shale, where we had existing conventiona
production as a result of historical development activities in east Texas and north Louisiana. Our operations in the Haynesville Shale are
primarily focused in DeSoto Parish and Caddo Parish, Louisiana. We acquired additional leasehold interests through the acquisition of
Peoples Energy Production Company in 2007. We piloted horizontally drilled wells in the Haynesville Shale, experimenting with different
horizontal lateral lengths and fracture stimulation staging, with the objective of delivering optimal capital efficiency, finding costs and
returns. High production rates in our Haynesville program combined with very low operating and development costs create competitive
returns for us even at low natural gas prices. In addition, our acreage in the Haynesville Shale is predominately held by production, giving
us the flexibility to pace our development and optimize our returns. Furthermore, our operations are surrounded by existing infrastructure,
providing strong take-away access to markets. As of June 30, 2012, we had 101 net operated wells in this area. During the first quarter of
2012, although we had a very efficient drilling program in the Haynesville Shale, we suspended the program and released all rigs due to
low natural gas prices.
Eagle Ford Shale
Beginning in late 2008, we were an early entrant in the Eagle Ford Shale, acquiring our interests through leasehold acquisitions for les
than $1,000 per acre on average. Our operations in the Eagle Ford Shale are focused in LaSalle, Dimmit, Atascosa and Webb counties of
south Texas. Overall, we hold rights to approximately 157,000 net acres across all Eagle Ford areas, where approximately 77,000 net acre
are under development in our central Eagle Ford area. During 2010 and 2011, we improved the efficiency and productivity of our
development program, reducing per-well capital costs by approximately 16% and drilling cycle time by more than 35% year over year.
Most of our wells have had initial production rates that range from 600 to over 1,000 Boe/d, and our oil production in this area has grown
significantly since the beginning of 2011. The Eagle Ford Shale currently provides the highest economic returns in our portfolio. Significan
strengths of the Eagle Ford Shale also currently include a multi-year future drilling location inventory, favorable crude oil pricing relative t
the West Texas Intermediate ("WTI") index and a newly constructed midstream infrastructure with ample take-away capacity. As a result,
the Eagle Ford Shale has become one of our key programs and a contributor to the increase in our oil reserves and production. As of
December 31, 2011, we had 1,246 future drilling locations in the Eagle Ford Shale. As of June 30, 2012 we had 98 net operated wells and
are currently running four rigs in the Eagle Ford Shale. We plan to add a fifth rig and drill 79 gross wells in 2012 based on our capital
budget.
Wolfcamp Shale
In 2009 and 2010, we established a new major oil shale position by successfully leasing approximately 138,000 net acres in the
Wolfcamp Shale in the Permian Basin in west Texas. Our operations in the Wolfcamp Shale are focused in Reagan, Crockett, Upton and
Irion counties. We were an early entrant in the Wolfcamp Shale, acquiring our interests through leasehold acquisitions for less than $1,500
per acre on average. We have leveraged our technical and operating expertise, and in 2011 advanced our understanding of this area using th
same approach and techniques that have allowed us to be successful in the Haynesville and Eagle Ford shales. As a result, in late 2011, we
completed a 7,500 foot lateral well with 25 stages that tested at an initial production rate of 1,369 Boe/d, our highest initial production rate
to date. In addition, the Wolfcamp Shale has high oil in place, a multi-year

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future drilling location inventory and favorable lease owner dynamics with the Texas University Land system as the predominant landowne
As of December 31, 2011, we had 983 future drilling locations in the Wolfcamp Shale. As of June 30, 2012, we had 26 net operated wells
and are currently running one rig in the Wolfcamp Shale. We plan to drill 15 gross wells in 2012 based on our capital budget.
Altamont Field
In 2007, we commenced a reengineering effort in the Altamont Field in Utah, a legacy oil asset. Our operations in the Altamont Field
are focused in the Uinta Basin. Altamont was initially developed in the 1970s, and we are applying current drilling and stimulation
technology to vertically drill and develop this prolific oil area. We have enhanced the value of this field through infill drilling, for which w
received regulatory approval in 2008. The Altamont Field has a multi-year inventory of future drilling locations, giving us a substantial
opportunity for growth in oil production. Since our acreage is predominantly held by production, we have greater flexibility to improve bot
our costs and technical understanding of this area, while also growing returns. As of December 31, 2011, we had 1,336 future drilling
locations in the Altamont Field. As of June 30, 2012, we had 307 net operated wells and are currently running two rigs in the Altamont
Field. We plan to drill 21 gross wells in 2012 based on our capital budget.
South Louisiana Wilcox
In south Louisiana, we are developing our emerging South Louisiana Wilcox play. This is a relatively new oil-focused play that we
have added to our drilling program. Our activity is located primarily in Beauregard Parish and is focused on the Wilcox Sands. We have
over 1,000 square miles of 3-D seismic data in South Louisiana Wilcox, providing valuable information in selecting drilling locations.
South Louisiana Wilcox is a conventional vertical well play that produces both oil and natural gas from a series of completed sands. A
significant strength of South Louisiana Wilcox is its access to Louisiana Light Sweet Crude and Gulf Coast NGL pricing, which trade at a
premium relative to the WTI index. In addition, the resource does not compete for horizontal drilling and completion services due to vertica
drilling and completion design. As of December 31, 2011, we had 260 future drilling locations in South Louisiana Wilcox. As of June 30,
2012, we had 19 net operated wells and are currently running one rig in South Louisiana Wilcox. We plan to drill 15 gross wells in 2012
based on our capital budget.
Other Gas Assets
We have a large and diverse base of other domestic producing assets that provides cash flow to fund the development of our key
programs. We do not anticipate a material portion of our 2012 capital expenditure budget to be spent on these assets.
Arklatex/Unconventional
Our Arklatex land positions comprise 104,470 total net acres focused on tight gas sands production. We have approximately 449,000
net acres in our unconventional plays. Our production is from vertical CBM wells development in Alabama, vertical and horizontal CBM
wells in the Hartshorne coals in Oklahoma and the New Albany Shale in Indiana (sold in July 2012). We have high average working
interests and long life reserves in these areas. For the six months ended June 30, 2012 we had average daily production of 119 MMcfe/d.
Texas Gulf Coast/Gulf of Mexico
We have significant assets in fields throughout the Texas Gulf Coast. In addition, prior to selling our Gulf of Mexico assets in July
2012, this area included interests in 69 Blocks offshore of the

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