atp - ipaa 2012 presentation final 2[1]

8/12/2019 ATP - IPAA 2012 Presentation Final 2[1]

1/35

Al Reese, Jr.

Chief Financial Officer

IPAA OGIS New YorkApril 17, 2012


2/35

1

Certain statements included in this presentation contain "forward-looking statements" within the meaning of the safe

harbor provisions of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as

amended, and Section 21E of the Securities Exchange Act of 1934. ATP cautions that assumptions, expectations,

projections, intentions, plans, beliefs or similar expressions used to identify forward-looking statements about future

events may, and often do, vary from actual results and the differences can be material from those expressed or

implied in such forward looking statements. Some of the key factors which could cause actual results to vary from

those ATP expects include, without limitation, volatility in commodity prices for crude oil and natural gas prices,

condition of the capital markets generally, as well as ability to access them, the timing of planned capital

expenditures, availability of acquisitions, uncertainties in estimating reserves and forecasting production results,

operational factors affecting the commencement or maintenance of producing wells, the and uncertainties regarding

environmental regulations or litigation and other legal or regulatory developments affecting its business. ATP assumes

no obligation and expressly disclaims any duty to update the information contained herein except as required by law.

ATP generally discloses, in filings made with the SEC, only proved reserves that can demonstrate by actual production

or conclusive formation tests to be economically and legally producible under existing economic and operating

conditions. ATP and its independent third party reservoir engineers use the term "probable" to describe volumes of

reserves potentially recoverable through additional drilling or recovery techniques that the SEC's guidelines prohibit a

company from including in proved reserves. These estimates are by their nature more speculative than estimates of

proved reserves. Any estimates of probable reserves in this presentation are based on the December 31, 2011 reports

of our independent third party engineers. PV-10 is a non-GAAP financial measure because it excludes income tax

effects. Management believes that the presentation of PV-10 provides useful information to investors because it is

widely used by professional analysts and sophisticated investors to evaluate oil and gas companies. PV-10 is not a

measure of financial or operating performance under GAAP. The most directly comparable GAAP financial measure is

the standardized measure of discounted future net cash flows. PV-10 should not be considered a substitute for the

standardized measure of discounted future net cash flows as defined under GAAP, which is calculated at year end

under accounting rules by applying pricing assumptions of the SEC to its proved reserves. More information about the

risks and uncertainties relating to ATP's forward-looking statements is found in the companysSEC filings or website

www.atpog.com.

Corporate Headquarters

4600 Post Oak Place, Suite 100Houston, TX

77027- 9726Telephone: (713) 622 3311IR Fax: (713) 622 6829

Forward Looking Statements

Investor Relations

Al Reese, Jr.Chief Financial Officer

Tom Kucera, CFADirector of Financial Analysis

Henry Coulter, CPAFinancial Analyst

Isabel PlumeChief Communications Officer

Sheila ThorntonCommunications & CorporateAffairs Specialist

[email protected]

www.atpog.com

NASDAQ: ATPG


3/35

Four Core Areas of Operation

Offshore acquisition,development andproduction of oil andnatural gas

Focused primarily onoil-weighted reservoirs

Future productiongrowth from existingproved undevelopedreserves

Operate infrastructureassets which arecomplementary to lowrisk hub development

Recent expansion intodeepwater Israelprovides upsidepotential

(1) Refer to Appendix for additional information.

Note: All reserve figures based on third-party reserve reports as of 12/31/2011.

2

MMBoe % of Reserves

North Sea 64.7 31%

GOM Shelf 8.8 4%

GOM Deepwater 137.8 65%

Mediterranean Sea - -

Total Proved & Probable 211.3 100%PV10 $7.68 billion

(1)

MMBoe % of Reserves

North Sea 64.7 31%

GOM Shelf 8.8 4%

GOM Deepwater 137.8 65%

Mediterranean Sea - -

Total Proved & Probable 211.3 100%PV10 $7.68 billion

(1)

Core areas of operations

MMBoe% of

Reserves

North Sea: 63.9 33.0%

GOM Shelf: 5.3 3.0%

GOM Deepwater: 125.2 64.0%

Mediterranean Sea:

Total Proved & Probable 194.4 100.0%

PV-10 $7.3 billion(1)


4/35

Probable

reserves =

75.5

Mmboe

Proved

reserves =

118.9

Mmboe

Low Risk Development Portfolio

3

Large inventory of proved and probable reserves to develop

- Known hydrocarbons with no exploration risk- 98% success rate converting undeveloped properties to production

- Proved reserves consist of 66% oil / 34% natural gas

Development projects drive long-term production growth

Oil66%

U.K. Gas15%

U.S. Gas19%

Proved and Probable = 194.4 MMBoeProved and Probable SEC PV-10 = $7.3 billion

Proved reserves = 118.9 MMBoeProved reserves SEC PV-10 = $4.2 billion

2011YE Proved reservecomposition

2011YE Proved and Probable reservecomposition

Pre-tax PV-10 of 2011YE proved reserves increased 50%+ over 2010

SEC PV-10= $4.2 billion

SEC PV-10= $3.1 billion

Note: All reserve figures based on third-party reserve reports as of 12/31/2011. See appendix for price deck detail.


5/35

16.1

21.0

24.6

2009

average rate

2010

average rate

2011

average rate

2012

Production in Avg. MBoe/d

FourthTelemark well(MC 942 A-3)

Workovers atMC 941 A-1 &A-2

Clipper onproduction

2013 Growth Drivers

Full year of Telemarkproduction with fourwells online

Full year of Clipperproduction

Two additional wellsat Gomez (#9 & 10)

Greater realizationsper barrel due todecrease in NPI / ORRIpayout %

Annual Production Growth Expectedto Continue

4


6/35

ATP is at an Inflection Point

5

Experiencing significant improvement in production ratesand oil production mix

Substantial decline in infrastructure capital expendituresgoing forward

Growing production and cash flow further enhanced bythe paydown of current NPIs and ORRIs, which results inincreased cash flow to ATP

Initial wells at Clipper have some of the highestdeliverability rates of any current and historical ATP oiland gas wells


7/35

Liquidity is Sound

6

Estimated cash position of $200+ million at 3/31/2012

No near-term debt maturities or maintenance financialcovenants

ORRI and NPI repayments tied directly to productionrevenues

Major infrastructure projects near completion


8/35

Production

Reserves

2012 Multiple Catalysts for ATP

MC 941 A-1 & A-2workover

4-7 MBoe/d netincremental productionestimate

Work currentlyunderway

Results of initial

exploration well in Israel Spud date in late April

2012

Potential to add 0.9-1.2Tcf of reserves

First production atClipper

Late 3Q2012 /early 4Q2012estimated

2 wells tested at 16MBoe/d net combined

MC 942 A-3 (completed)

4th well at Telemark

Online February 25,2012

>7 MBoe/d

2Q 3Q 4Q1Q

7


9/35

Estimated cash balance of $200+ million at 3/31/2012

First quarter production estimated at 1.8 1.9 MMBoe (65%+ oil and condensate)

Progress at Telemark

MC 942 A-3 well is on production

MC 941 A-1 & A-2 workovers in progress

Clipper on track for production late 3Q2012 / early 4Q2012

Preparation for first exploration well in Israel

Spud date of first well expected in late April 2012

On March 15, 2012 ATP was awarded the Safety-in-Seas Award from the National Ocean IndustriesAssociation. ATP was chosen by a blue-ribbon panel of judges from among multiple nominees.The national award recognized ATP for its exemplary contribution to the safety of offshore energyworkers, as well as for the design conceived three years prior to the Macondo incident andsafety-redundancy of theATP Titan, a technologically advanced deepwater drilling andproduction platform in the Gulf of Mexico.

First Quarter Update

8


10/35

99% of all proved reserves on a PV-10

basis are operated by ATP- Ability to control costs and timing

- Ability to manage operating risksthrough sell down of interests

- Known track record of developingassets

Deepwater operating expertise

- ATP ranks 4th overall in deepwaterGulf of Mexico wellbores

- Expertise provides ATP new globalopportunities

Experienced and incentivizedmanagement and technical teams

- Deep technical team with averageexperience of over 25 years

- Key members of senior managementteam have worked together since1984

- Senior management and directorsown ~15% of ATP

- Every employee has an ownershipstake in ATP

2

2

3

3

4

4

5

6

7

7

8

9

14

16

17

18

18

28

40

53

LLOG

Petrobras

Newfield

Nexen

Marathon

Noble

Murphy

Chevron

ERT

Mariner

Hess

Marubeni

BHP

Exxon

Walter

Eni

ATP

Anadarko

BP

Shell

Deepwater Gulf of Mexico Wellbores (including Majors)

Note: Does not include eight companies, each of which has one wellbore.

Source: BOEM website 2010

Proven Offshore Operator with ExperiencedManagement

Majors

Independents

ATP (Independent)

9


11/35

ATP owns substantial infrastructure assets in operation today and additional assets are under

construction with deployment scheduled in 2014

Long-lived re-useable assets (20 - 50 years) are key to ATPs hub strategy

ATP will continue to operate and control its assets

Complete & Producing Under Construction

Reusable Floating Deepwater Infrastructure

Initial Installation Gomez Hub Telemark Hub Cheviot Hub

Capacity 20 MBbls/d / 100 MMcf/d 25 MBbls/d / 50 MMcf/d(1)

25 MBbls/d / 50 MMcf/d

In Service / Utility 2006 / >20 yrs 2009 / >40 yrs 2014 / >50 yrs

Water Depth Range 300' - 3,500' 1,500' - 9,500' 500' - 9,500'

% Ownership 51%(2)(3)

100%(3)

100%

(1) Expandable to 100 MMcf/d.(2) Created an SPV by selling 49% ownership in theATP Innovatorto GE Financial Services for $150 million.(3) Ownership held in ATP-owned SPV.

Fleet of Re-usable Floating DeepwaterInfrastructure

10

ATP Innovator - Gomez Hub ATP Titan

Telemark Hub Octabuoy - Cheviot Hub


12/35

Canyon Express

Telemark

Gomez

Clipper

Entrada

Ladybug

Hub strategy improves

economics and growthopportunities. Future Development

Producing

Producing + Future Development

11

Deepwater Gulf of Mexico Operations


13/35

14.819.5

7.9

8.9

22.2

2003 (Inception) 2011

Production (MMboe)

Probable reserves (MMBoe)

Proved reserves (MMBoe)

50.6

22.7

Gomez Hub Telemark Hub Clipper Project

22.5

38.8

8.4

16.7

5.3


Production (MMboe)



60.8

30.9

7.18.2

4.3

5.4




13.6

11.4

History of outperforming initial third-party reserve estimates

12

The value of deepwater is that reserves tend to increase alongside production

Deepwater Math



14/35

13

Summary:

Acquired MC 941, MC 942 & AT 63 in 2006

Acquired AT 19 & AT 62 in 2008

ATP operates with a 100% WI

Initial production started March 2010 at theTelemark Hub

Water depth ~4,000 ft

MC 942 A-3 well on production Feb 25,2012

MC 941 A-2 well workover in progress

MC 941 A-1 producing; sleeve shiftscheduled after completion of A-2 workover

AT 63 producing

Telemark Hub Property Overview


2011YE:38.8 MMBoe Proved Reserves (79% Oil)

55.5 MMBoe Proved & Probable Reserves (85% Oil)

Shell/ StatoilHydro/ Anadarko Vito discovery, July 29,2009: Well encountered more than 250 net feet of oil

pay in subsalt Miocene sands

MC 940MC 941

100% WI

MC 942

100% WIMC 943

MC 987MC 986MC 985MC 984

Vito

AT 16 At 17 AT 18AT 19

100% WI

AT 63

100% WI

AT 62

100% WIAT 61AT 60

ATPTitan

ATP blocks


15/35

14

Summary

Acquired by ATP in 2008, operated with100% WI

- Discovered in 2005 by Pioneer NaturalResources


GC 300#2 well completed in July 2011(Flow-tested at 12.3 MBoe/d)

GC 300#4 well completed in December 2011(Flow-tested at 9.8 MBoe/d)

Combined test: 22.1 MBoe/d (16.4 MBoe/dnet; 62% oil)

First production expected from both wellslate 3Q2012 / early 4Q2012

Clipper (Green Canyon Block 300)

Status update


2011YE:

8.2 MMBoe Proved Reserves (72% Oil)


Pipeline to 3rd party platform, currently in progress,scheduled for 3Q2012 (lay barge contracted for July)

Onsite work at Murphy Frontrunner, the host platform,commenced

Clipper tested at 67 percent ofATPs 2011 average daily production

MBoe/d

16.4

24.6

Clipper combined test

(production expected 3Q2012 /

4Q2012)

ATP

2011


16/35

EntradaGarden Banks Block 782

15

Acquired in 2010


Previous drilling found logged hydrocarbonsin 7 wellbores

ATP operates with 100% WI

Development currently scheduled for 2013 2014

Application for Development Plan in processin accordance with recent regulations

Expect probable reserves to convert toproved upon drilling of first well


2011YE:




17/35

North Sea Operations

Cheviot

Skipper

Helvellyn

Wenlock

Blythe

L-6d

Tors

Future Development

Producing

Producing + Future Development

16


18/35

17

Cheviot Hub


COSCO Shipyard, Nantong, China, March 2012

2011YE:



Cheviot First oil expected in 2014

Anticipated peak production of25 MBbls/d and 50 MMcf/d


In active discussion with potentialworking interest partners

Extensive technical analysis, includingreservoir simulation, performed by ATP

Filed field development plan4/15/2011

Octabuoy (Under Construction)- Cheviot Hub


19/35

Daniel EastDaniel EastShimshonShimshon

Daniel WestDaniel West

DiscoveriesDiscoveries

ATP AcreageATP Acreage

LeviathanLeviathanTamarTamar

DalitDalit

Cyprus

Block 12

Cyprus

Block 12

18


Anticipate initial drilling to begin 2Q2012

- ATPs portion: $24$29 million

Water depth 3,622 ft., target depth 14,764 ft.

Lockwood & Assoc. estimated Shimshonspotential gas reserves:

- Gross: 2.5 3.4 Tcf

- Net to ATP: 0.9 1.2 Tcf

Mediterranean Licenses

Shimshon Property Overview

Israel Market Pricing

Current local gas price in excess of $6.50/Mcf

Current LNG prices of $89/MMBtu to Europe and $1416 to Asia

A O i i Off h l


20/35

ATPs Opportunity in Offshore IsraelProvides Additional Upside

Three Deepwater Licenses:

- Operator of all three licenses- Ownership ranges from approximately 30% to 50%

- Minimal upfront investment

Key Points:

- Small cost for extremely large potential

- Opportunity to enter world class area during the early stages of exploration and development

- Enhances future ability to acquire and develop proved undeveloped assets in this region

0

4

8

12

16

Leviathan

Israel

Tamar 1

Israel

Dhirubhai 1

Indonesia

Poseidon 1

Australia

Dhirubhai 3

Indonesia

Arous El Bahar

Libya

Pluto

Australia

Clio 1

Australia

Windjammer 2

Mozambique

Chandon 1

Australia

Large Potential in Israel

RecoverableNatural

Gas(Tcf)

Source: IHS-EDIN database.Filtered for non-associated gas fields, water depth greater than 1,000 ft and discovery date from 2001-2010.

19

For low costs ATP will evaluate ~1 TCF net

Top 10 Deepwater Gas Discoveries Worldwide (2001 2010)

E M di R i l


21/35

East Mediterranean Rationale

6 successful exploration wells out of 6 attempts since drilling began in 2008 fordeepwater subsalt targets

Elephant-sized natural gas discoveries totaling 35 Tcf (5.8 bn Boe) and $285 bn of revenue potential

Tamar & Leviathan fields, two of the largest deep water natural gas discoveries of the last decade

Large natural gas discovery in Cyprus Block 12

Significant remaining potential of gas and oil in the area

Noble Energy has resumed drilling Leviathans deeper oil prospects estimated to hold ~2.4 bn Bbls

20

SIGNIFICANT SUBSALT MIOCENE DISCOVERIES

Noble Energy

enters Israel

Yam Tethysdiscoveries

(1.2 TCF)

Tamardiscovery

(9.1 TCF)

Leviathandiscovery

(17 TCF)

Cyprusdiscovery

(7 TCF)

Tanindiscovery

(1.2 TCF)

L T C it l & L


22/35

Long-Term Capital & Leverage

First lien and second lien debts have no maintenance financial covenants and mature in2015

ATP began granting NPIs & ORRIs to a combination of vendors and financial firms in 2009

- Attractive from a liquidity standpoint because payments are proportional to ATP

production and pricing from a given property or properties

- Higher prices, higher production = Faster payoff

- Lower prices, lower production = Smaller payments

ATP estimating 3040% of 2012 revenue will be directed to servicing NPIs & ORRIscurrently outstanding; percentage expected to decrease in latter part of 2012 andreduce to 1520% in 2013

- Another source of increasing available cash flow to ATP above and beyond expected

increase in production volumes21

Note: See appendix for outstanding amounts.

2012 C it l O tl k


23/35

2012 Capital Outlook

2012 Capital Plan

- ATP's 2012 capex plans call for $400500 million in total capital expenditures

- $5070 million is expected to be contributed by vendors through existing NPI ordeferral programs

Development:

- GOM Telemark MC 942 A-3 on production- Currently conducting workover on MC 941 A-2 with sleeve shift then scheduled

on MC 941 A-1

- GOM Gomez #9 and #10 wells. Start in late 2012. Primarily a 2013 development

- GOM Clipper pipeline

- North Sea Cheviot, sub-sea trees ordered

Infrastructure:

- North Sea Octabuoy topsides, schedule being finalized, favorable vendor financing

Exploration:

- Israel Shimshon well, targets ~1TCF @ $0.03/MCF22

K I t t Hi hli ht


24/35

Key Investment Highlights

ATP is at an inflection point

- Experiencing significant improvement in production rates and oil production mix

- Substantial decline in infrastructure capital expenditures going forward

- Growing production and cash flow further enhanced by the paydown of current NPIs

and ORRIs, which results in increased cash flow to ATP

Liquidity is sound

- Estimated cash position of $200+ million at 3/31/2012

- No near-term debt maturities or maintenance financial covenants

- ORRI and NPI repayments tied directly to production revenues

- Major infrastructure projects near completion

23

K I t t Highlight ( td)


25/35

Key Investment Highlights (contd)

Deepwater operating expertise

- ATP ranks 4th overall in deepwater Gulf of Mexico wellbores; this expertise hasprovided ATP new global opportunities

Fleet of Re-usable Floating Deepwater Infrastructure

- ATP owns substantial infrastructure assets in operation today; additional assets underconstruction with deployment scheduled in 2014

- ATP will continue to operate and control its assets

Substantial asset value

- Proved and probable reserves of 194.4 MMBoe (66% oil) with SEC PV-10 of $7.3 billionat 12/31/11

- Infrastructure investment of over $1.0 billion

Strong alignment of shareholders, management and employees

- Every employee is an owner of ATP

- Management and Directors own ~15% of ATP

- Key management members have worked together since 1984

Note: All reserve figures based on third-party reserve reports as of 12/31/2011. Refer to appendix for additional information. 24


26/35

25

ATP Oil & Gas Corporation (NASDAQ: ATPG)

ATP Oil & Gas Corporation4600 Post Oak Place , Suite 100Houston, TX 77027-9726713-622-3311

ATP Oil & Gas (UK) LimitedVictoria House, London Square, Cross LanesGuildford, Surrey GU1 1UJ

United Kingdom44 (0) 1483 307200

ATP Oil & Gas (Netherlands) B.V.Water-Staete GebouwDokweg 31 (B)1976 CA IJmuidenThe Netherlands

31 (0) 255 523377

ATP East Med B.V.15 Aba Even StreetHerzliya Pituach 46725Israel

www.atpog.com

ATP Innovator

ATP Titan Octabuoy


27/35

26

Appendix

Gomez Hub


28/35

Gomez Hub

Acquired in 2003

- First production in 2006

- Still producing from initial zones


ATP operates

Six wells on production

DOCD for MC 711#9 and #10 approved January 20,2012. Wells planned in late 2012-early 2013

Exploration upside

27

Summary ATP Innovator - Gomez Hub

MC 666MC 667

100% WI

MC 668

100% WI

MC 710 MC 711100% WI

MC 712

MC 754

75% WIMC 756

MC 798 MC 799 MC 800

MC 755

100%

100% WI

ATP blocks

ATPInnovator

MC 666MC 667

100% WI

MC 668

100% WI

MC 710 MC 711100% WI

MC 712

MC 754

75% WIMC 756

MC 798 MC 799 MC 800

MC 755

100%

100% WI

MC 666MC 667

100% WI

MC 668

100% WI

MC 710 MC 711100% WI

MC 712

MC 754

75% WIMC 756

MC 798 MC 799 MC 800

MC 755

100%

100% WI

ATP blocks

ATPInnovator


2011YE:19.5 MMBoe Proved Reserves (64% Oil)


Hub Concept Improves Economics & Growth


29/35

Hub Concept Improves Economics & Growth

Low-risk development strategy

- Hubs encourage development of neighboring projects

- Proved undeveloped reserves with logged hydrocarbons and extensive seismic

- Staged hub development and operating control provide timing and cost flexibility

Cost effective development plan aided by infrastructure

- Infrastructure assets complementary to strategy

- Application of award-winning innovations and technologies, include 16 patentsawarded and 5 pending and 5 additional filings awaiting first action for a total of 26inventions and systems

- Long-lived re-locatable assets (20 - 50 years)

28

ATPs Hub Concept is a low-risk, cost-effective development strategywith significant growth opportunities

Financial Strategy & Risk Management


30/35

Financial Strategy & Risk Management

Capex program continues to focus on development of proven reserves rather thanexploration

Monetize assets and access the equity capital markets when appropriate

Establish SPVs for major infrastructure assets with equity partners or non-recourse debt

Manage leverage and liquidity

Operate properties to control development plan and timing of capital expenditures

Maximize value creation of hubs and other development projects, then reduce exposure

Maintain appropriate capital structure

Utilize multiple capital raising alternatives

Pursue an active oil and gas hedging program

Maintain a comprehensive insurance program

29

Financial Strategy

Managing Risk

Telemark Wells


31/35

Telemark Wells

30

Drilling order Name Description

1 AT 63 #SS04 Atwater Valley 63

2 MC 941 A-1 Mississippi Canyon 941 #3



Price Deck


32/35

Price Deck

(1) Based on USD/GBP conversion rate at $1.55/GBP on 12/31/11.

NYMEX UK Gas

(1)

Crude Natural gas Natural gas

($/Bbl) ($/MMBtu) ($/MMBtu)

YE 2011 SEC pricing $96.19 $4.12 $9.02

31

Derivatives Summary


33/35

Derivatives Summary

32

2Q 3Q 4Q FY 1Q 2Q 3Q 4Q FYGulf of Mexico

Natural Gas Calls

Volumes (MMMBtu) 910 920 920 2,750 - - - - -

Price ($/MMBtu) 5.30$ 5.30$ 5.50$ 5.37$ - - - - -

Crude Oil Swaps

Volumes (MBbls) 751 759 759 2,269 315 228 230 230 1,003

Price ($/Bbl) 97.36$ 97.36$ 97.36$ 97.36$ 103.60$ 108.88$ 108.88$ 108.88$ 107.22$

Prepaid Crude Oil S waps(1)

Volumes (MBbls) 268 202 104 575 - - - - -

Price ($/Bbl) -$ -$ -$ - - - - - -

Crude Oil Basis Swaps

Volumes (MBbls) 273 276 205 754 233 182 184 184 783

Basis Price ($/Bbl, LLS - WTI) 13.53$ 10.90$ 10.39$ 11.71$ 5.06$ 4.18$ 4.18$ 4.18$ 4.44$

Crude Oil Swaptions (Calls Sold)(2)

Volumes (MBbls) - - - - 90 91 92 92 365

Strike Price ($/Bbl) - - - - 96.50$ 96.50$ 96.50$ 96.50$ 96.50$

North Sea

Natural Gas Swaps

Volumes (MMMBtu) 455 460 460 1,375 180 - - - 180

Price ($/MMBtu)(3)

8.26$ 8.26$ 10.13$ 8.88$ 11.28$ - - - 11.28$

(2) Call swaptions sold to a third party that allows the third party to exercise and enter into a swap with ATP at the strike price.(3) Assumes currency trans lation rate of 1.60 USD per GBP which approximates the rate as of April 13, 2012

Additional hedges, derivatives and fixed price contracts, if any, will be announced during the year.

(1) ATP received cash proceeds at closing averaging approximately $105.03 per barrel. During the future

contract settlement months, ATP will pay cash based on the prevailing market prices in effect at that time,

which may be more or less than ATP were paid.

Derivatives Schedule

(Unaudited)

2012 2013

The above are ATP's financial and physical commodity contracts outstanding as of April 13, 2012

Long-Term Patient Corporate Leverage Structure


34/35

Long-Term Patient Corporate Leverage Structure

$1.5 billion aggregate principal amount with an 11.875% interest rate and May 2015maturity

$365 million senior secured term loan

March 2011 increased amount from $150 million to $210 million, decreased rate from 11%to 9% and extended maturity from October 2014 to January 2015

March 2012 increased amount from $210 to $365 million and decreased rate from a 9.00%

to 8.75%

33

High yield bonds (April 2010)

Managing Risk

Debt & Other Obligations


35/35

Debt & Other Obligations

(1) Pro forma values, including additional financings after 12/31/2011.

12/31/2011

Net profits interests (Telemark Hub, Gomez Hub and Clipper) $336.7 (1)

Dollar-denominated overriding royalty interests (Gomez Hub) 227.3 (1)

Other long-term obligations 186.5

Total long-term obligations $750.5

First lien term loans 359.7 (1)

Second lien bonds 1,495.3

ATP Titan, LLC term loan 310.0

Total $2,935.5

atp - ipaa 2012 presentation final 2[1]

Documents