Aug2009 ATP Presentation

8/22/2019 Aug2009 ATP Presentation

http://slidepdf.com/reader/full/aug2009-atp-presentation 1/29

The Oil & Gas Conference

August

9

– 13,

2009



Forward Looking Statement

Certain statements included in this news release are “forward‐looking statements” under the Pri va te

Securities Litigation Reform Act of 1995. ATP cautions that assumptions, expectations, projections,

intentions, or beliefs about future events may, and often do, va ry from actual results and the differences can

be material. Some of the key factors which could cause actual resul ts to va ry from those ATP expects include

changes in natural gas and oil prices, the timing of planned capital expenditures, availability of acquisitions,

uncertainties in estimating proved reserves and forecasting production results, operational factors affecting

the commencement or maintenance of producing wells, the condition of the capi tal markets generally, as

well as our ability to access them, and uncertainties regarding environmental regula tions or litigation and

other legal or regulatory developments affecting our business. The SEC has generally permitted oil and gas

companies, in filings made with the SEC, to disclose only proved reserves that a company has demonstrated

by actual production or conclusive formation tes ts to be economically and legally producible under existing

economic and operating conditions. We and ou r independent thi rd party reservoir engineers use the terms

"probable" and “possible” and we use the term “recoverable hydrocarbons” to describe volumes of reserves

potentially recoverable through additional drilling or recovery techniques that the SEC's guidelines may

prohibit us from including in filings with the SEC. These estimates a re by their nature more speculative than

estimates of proved reserves. All estimates of probable and possible reserves in this news release have been

prepared

by

ou r

independent

third

party

engineers

and

all

estimates

of

recoverable

hydrocarbons

ha ve

been

prepared by management. More information about the risks and uncertainties relating to ATP's forward‐

looking statements are found in our SEC filings. Unless otherwise indicated, all reserve figures a re per the

reserve report from the appropriate yea r.

Investor Relations

Al Reese, Jr.

Chief Financial Officer

Brian Nelson

Vice President, Finance

Isabel PlumeChief Communications Officer

Sheila Thornton

Communications & Corporate

Affairs Specialist

[email protected]

Corporate Headquarters

4600 Post Oak Place, Suite 200

Houston, TX

77027‐ 9726

Te le phone: (7 13 ) 622 3311

IR Fax: (713) 622 6829

www.atpog.com

NASDAQ ‐ ATPG

│2



Create value through low‐cost, low risk PUD conversion

Focus on acquiring properties with proved but undeveloped reserves

From 12/31/04 to 12/31/08, 57% of reserve growth from upside associated with revisions,

extensions, and discoveries (see appendix slide 29)

Operate

substantially

all

projects

in

development“Hub” concept improves economics and growth opportunities

Corporate Strategy

GOM Deepwater

53%(1)

GOM Shelf

10%(1)

North Sea

37%(1)

(1) Based on Proved Reserves a t December 31, 2008, using independent third‐party reserve engineers.

98% success rate converting properties from undeveloped to producing

│3│



$8.54

$45.51

$114.61

Market Price

Per

Share NAV

per

share NAV

per

share

NAV at

PV30

NAV at

PV10

What Makes ATP a Compelling Value?

Fundamental Valuation

as

of

June

30,

2009

PV‐10 at June 30, 2009 $5.3 billion(1)

Plus estimated infrastructure investment $1.0 billion

Less net

debt $(1.2)

billion

Net Asset Valuation (NAV) for shareholders $5.1 billion

Shares outstanding August 6, 2009 44.5 million

NAV per share at PV10 $114.61

│4

(1) Based on 6/30/09 strip pricing

(2) As of August 4, 2009

(2)




Successful Model

Through

All

Business

Cycles

98% success rate converting non‐producing properties to producing properties

Focus is acquiring and implementing development projects with identified reserves, not

pursuing

riskier

exploration

ideasControl and operate practically all properties – flexibility as to the timing of capital

expenditures and the scope of the development

Strong track record of monetizing assets

│5

Octabouy

ATP has

monetized

value

throughout

all

stages

of

the

development cycle and expects to continue this value creation

Acquisit ion

Development

Plan

Engineering

&

Procurement

Development

Program

Implemented

Field

Enhancement&

Add itional

Acquisit ion

Production

V a l u e

A d d e

d



$‐

$200

$400

$600

$800

$1,000

$1,200

$200

$400

$600

$800

$1,000

$1,200


│6

Infrastructure Investment

Dec 31, 2004 to June 30, 2009Change

in

Long

‐term

Debt

Dec 31, 2004 to June 30, 2009

Infrastructure Investment

at

Hubs

Since March 2009, ATP has received $150 million from strategic partners to participate in

ATP’s infrastructure projects

ATP is actively seeking investors for an additional $300 ‐ $700 million within the next year

By adding

partners

to

its

infrastructure

projects,

ATP

recoups

a significant

portion

of

its

investment, reduces its outstanding debt, owns all of the reserves, and continues to control

the infrastructure

From 12/31/04 to 6/30/09, ATP’s investment in infrastructure is similar to ATP increase in

long‐term debt

ATP Innovator

Gomez Pipeline

ATP Titan

Telemark Pipe line

Octabouy

Change in debt $1,104 m illion



‐

5.0

10.0

15.0

20.0

25.0

30.0

35.0

Mboepd


Telemark Hub

This property will more than double ATP’s current production rate

Approximately $1.0 billion invested to date

Suppliers have joined ATP to complete the development by contributing ~$200 million of

services that

they

will

recoup

from

production

Phase 1 of the development will bring over 25 MMBoe to production with Phase 2 adding

an additional 17 MMBoe around 2014

Christening of the ATP Titan, the floating drilling and production facility to serve

Telemark, is

scheduled

for

August

26,

2009 with

sail

out

activities

commencing

in

October

│7

IP 5 Years

Telemark Hub Net Production Profile(1)

ATP Titan Relocation

(1) Based on independent third‐party prepared reserves



Financial Position – J une 30, 2009

│8

Cash $ 100 million

Long‐term debt(1)(2)

Balance of $600 million

asset sale facility due 2011 $ 273 million

Revolver due 2013 $ 31 million

Term note

due

2014 $1,040

million

Total long‐term debt $1,344 million

Net long‐term debt $1,244 million

(1) No near

‐term

maturities

(2) No borrowing base redeterminations



│9

(1) Based on roll‐forward of year‐end reserves report prepared by independent third‐party reserve engineers

(2) Based on three‐year strip pricing at 6/30/09

(3) Based on three‐year strip pricing at 6/30/09 and includes 100% of Proved PV‐10 and 50% of Probable PV‐10

(4) See Appendix

for

more

detail

Debt Compliance – J une 30, 2009

Debt Coverage

Net Debt at 6/30/09 $1,244 million

Proved & Probable reserves(1) 193 million Boe

PV‐10 at 6/30/09(2) $5.3 billion

PV‐10 for loan covenants at 6/30/09(3) $4.1 billion

PV‐

10

for

loan

covenants

to

Net

Debt 3.6x

(debt

compliance

>2.5x)

TTM EBITDAX at 6/30/09(4) $485 million

Net Debt to TTM EBITDAX 2.3x (debt compliance <3.0x)



Re‐usable Floating Infrastructure Summary

Initial Installation Gomez Hub Telemark Cheviot

Oil Processing

Capacity

20 MBbls/d 25 MBbls/d 25 MBbls/d

Gas Processing

Capacity100 MMcf/d 50 MMcf/d 50 MMcf/d

In Service 2006 2009 2012

Expected Useful Life >20 yrs >40 yrs >50 yrs

Drilling Capability No Yes Yes

Water Depth Range 300’ ‐ 3,500’ 1,500’ ‐ 9,500’ 500’ ‐ 9,500’

Total Installed

Cost $300

million $600

million $600

million

ATP Innovator Octabouy ATP Titan

│10│



Monetizing Assets – Producing and Developing Properties

Gomez Hub (Gulf of Mexico)

ORRI sold for $82 million (~$102 / Bbl and ~$9 / Mcf)

Limited to 5.76 Bcfe

Closed June 9, 2008

Wenlock & Tors (U.K. North Sea)

Sale of 80% of ATP’s interest for £265 million or approximately $400 million at closing

Sale represented ~8% of ATP’s total Proved Reserves(1)

ATP remains

operator

Closed December 17, 2008

(1) Based on Proved Reserves a t December 31, 2008, using independent third‐party reserve engineers.

Vendors Participating in Development of Telemark Hub

Through the exchange of services for a limited net profits interest, over $200 million of

CAPEX participation

will

be

contributed

by

Diamond

Offshore

and

other

vendors

Future payments to vendors to come from production

│11│



Monetizing Assets ‐ Infrastructure

ATP Innovator GE Energy Financial Services joins ATP in ownership of

ATP Innovator Sale

of

49%

of

ATP’s

interest

in

the

ATP Innovator for

$150 million, effective June 1, 2008

ATP remains operator with 100% W.I. in remaining

reserves at Gomez

Closed March 6, 2009

ATP Titan and Telemark Hub Pipelines

Initial discussions with interested parties have begun

$554 million

invested

through

June

2009

in

the

ATP Titan and $160 million in the pipelines

ATP Innovator

ATP Titan

│12│



Proved & Probable Reserves

(1) Reserves prepared by independent third‐party engineers as of December 31, 2008 and rolled forward by ATP at June 30, 2009 using 3‐year strip prices.

As of June 30, 2009

Proved & Probable Reserves of 193 MMBoe(1)

PV‐10 of Proved & Probable Reserves $5.3 billion

Proved Reserves

of

119

MMboe(1)

PV‐10 of Proved Reserves $2.9 billion

│13│

Proved & Probable Reserves

‐ 20 40 60 80 100 120 140 160 180 200(MMBoe)

55% Oil 15% UK Gas 30% US Gas

Proved Reserves

‐ 20 40 60 80 100 120 140 160 180 200(MMBoe)

55% Oil 16%

UK Gas29% US Gas



2009 Development Update

2009 Property / Well Status

Gomez #8 sidetrack on production

Wenlock #2 on production

Wenlock #3 (Bodbury) on production

South Marsh Island 190 #2 well on production

Gomez Hub (tie‐back of MC 754/800) scheduled 2010

Canyon Express scheduled late 2009

Morgus / Mirage / Telemark Hub progressing rapidly (refer to slides 15‐18)

│14│



Telemark Hub ‐ Overview

Telemark Hub is a development project, not an exploration venture

Operate with

100%

W.I.

Eight wells previously drilled encountered 16 hydrocarbon bearing sands

Develop four wells ‐ two wells at Mirage (MC 941), one well at Morgus (MC 942), and

one at

Telemark

(AT

63)

‐during

Phase

1 and

3 to

4 additional

wells

at

AT

63

in

Phase

II

ATP Titan (MinDOC) installation expected to commence October 2009

Diamond Offshore and other vendors to join ATP by contributing an estimated $200

million towards completing theTelemark Hub

First production late 2009 or early 2010

Total third‐party Proved and Probable reserves of 42 MMBoe (76% oil)

│15│

Potential to more than double existing production in 2010 through Telemark Hub

development



Telemark Hub – Development Project

Morgus / Mirage

(MC

941

&

MC

942)

Three wells previously drilled by others at Morgus / Mirage in 1999

to depths of 14,000’ to 18,000’

The wells encountered four sands, which were evaluated with logs,

cores and fluid samples

Using the Ocean Victory, ATP has drilled two new wells to 12,000’

and a third new well should reach total depth in August 2009

22 MMBoe Proved and Probable reserves (78% oil)

Telemark (AT 63)

Five wells previously drilled by others at Telemark in 2000 ‐ 2003

to depths 20,000’ to 24,000’

The wells encountered 12 sands, which were evaluated with logs,

cores and fluid samples

Upside potential

as

no

water

contact

was

found

Note: AT 62, AT 63, AT 19 (Telemark); MC

941 (Mirage); MC 942 (Morgus)

MC 941

100% WI

MC 942

100% WI

MC 943

100% WI

MC 985 MC 986 MC 987

AT 17 AT 18AT19

100% WI

AT61AT62

100% WI

AT63

100% WI

ATP will use the Ocean Victory to re‐enter and complete the AT 63 Telemark well in the Revised

Phase I Development Plan, after the Morgus / Mirage wells are drilled

Well to be completed sub‐sea and tied into the ATP Titan in Phase I

3 to

4 development

wells

to

be

drilled

in

Phase

II Development

Plan

20 MMBoe Proved and Probable Reserves (73% oil) │16│



Telemark Hub – Infrastructure

ATP Titan ATP Titan over 95% complete with christening scheduled for

August 26, 2009

Installation scheduled at MC 941 October 2009, after the Ocean

Victory finishes drilling the one Morgus well and two Mirage wells

Completion of the one Morgus well and two Mirage wells to be

accomplished using the platform rig on the ATP TitanProduction capacity of 25 MBbls/d and 50 MMcf/d

Pipelines

62‐mile 10‐inch gas pipeline to Grand Isle 115 into the Discovery

gas system = Installed

20‐mile 10‐inch oil pipeline to Mississippi Canyon 718 into the

Shell Mars oil system = Installed

ATP Titan – 4,000’ water

│17│



Telemark Hub – Financial Plan

Development Plan

Approximately $1 billion invested by ATP through June 2009

~$554 million

in

the

ATP Titan, ~ $160 million

in

pipelines,

and

~$250 million in drilling and other

Total remaining Revised Phase I Development CAPEX estimate of

approximately $500

to

$600

million

through

the

end

of

2010,

includes Mirage (MC 941), Morgus (MC 942) and Telemark (AT 63)

45% to 55% of CAPEX to be absorbed by ATP’s vendors in

exchange for a limited net profits interest

Note: AT 62, AT 63, AT 19 (Telema rk);

MC 941 (Mirage); MC 942 (Morgus)

ATP Titan – 4,000’ water

MC 941

100% WI

MC 942

100% WI

MC 943

100% WI

MC 985 MC 986 MC 987

AT 17 AT 18AT19

100% WI

AT61AT62

100% WI

AT63

100% WI

│18│



Oil development focused E&P company with Gulf of Mexico Deepwater and

North Sea exposure

98% success rate converting undeveloped properties to developed

producing properties

Large inventory of reserves drive growth in 2009‐2012

Summary

│19│

ATP Innovator

ATP Titan

Tors

Infrastructure portfolio

adds

a potential

$1

billion

in

value

not

reflected

in

share price

Approximately $800 million of value generated in the past six months through

asset monetizations, plus other monetizations in active negotiations

Potential to more than double existing production in 2010 through

Telemark Hub development

Compelling fundamental

value

– Discounted

NAV

many

times

greater

than current share price



ATP Oil & Gas Corporation

4600 Post Oak Place,

Suite 200

Houston, TX 77027‐9726

713‐622

‐3311

ATP Oil & Gas (UK) Limited

Victoria House, London Square, Cross Lanes

Guildford, Surrey GU1 1UJ

United Kingdom

44 (0) 1483 307200

ATP Oil & Gas (Netherlands) B.V.

Water‐Staete Gebouw

Dokweg 31

(B)

1976 CA IJmuiden

The Netherlands

31 (0) 255 523377

www.atpog.com

ATP Oil & Gas Corporation NASDAQ: ATPG

Octabuoy

ATP Innovator

ATP Titan

│20│



ATP Innovator – 3,000’ waterAugust 2009 Property Update

#8 well completed, online and producing March 2009

Five wells on production

Additional

zone

change

scheduled

with

a

potential

sleeve shift for a well later in 2009

Anduin West and Gladden scheduled production start

2010 (development operator – Newfield)

MC 666MC 667

100% WI

MC 668

100% WI

MC 710MC 711

100% WIMC 712

MC 754

25% WIMC 756

MC 798 MC 799MC 800

10% WI

MC 755

100%

Property Economics

First production March 2006

Cash on cash payout August 2008

Note: MC

711,

MC

667,

MC

668

(Gomez);

MC

755

(Anduin); MC 754 (Anduin West); MC 800 (Gladden)

Appendix ‐ Gomez Hub

│21│

Pipelines

~$85 million installed cost

Two separate oil and gas pipelines, 27 miles to Grand Isle

115 into Amberjack oil system and Discovery gas system

Oil pipeline: 8‐inch, 30 MBbls/d capacity

Gas pipeline: 10‐inch, 100 MMcf/d capacity



Appendix ‐ Wenlock

August 2009 Property Update

Wenlock #2 well on production March 2009 with a

~3,000’ horizontal section

Bodbury well (Wenlock #3) encountered targeted

sands and was placed on production June 23, 2009

Operate with a 20% working interest

Wenlock Platform

Wenlock Field Map

│22│



Appendix – EBITDAX

│23│

ATP Oi l & Gas Corporation

Rolli ng EBITDAX Calculation

Consolidated

Quarter Quarter Quarter Quarter

($ thousands) 3Q08 4Q08 1Q09 2Q09 TTM

Conso lidated Net Income (loss) 36,483 50,157 1,636 (4,366) 83,910

Consolidated EBITDAX

Add to consolidated Net Income (loss):

Income taxes 5,534 31,232 (874) (1,174) 34,718

Consolidated Interest Expense (per income statement) 26,606 21,760 12,623 10,174 71,163

DD&A 52,825 24,337 39,398 43,575 160,135

Exploration - G&G 199 - 174 93 466 Noncash compensation expense 3,276 3,354 2,195 2,084 10,910

Other noncash charges:

Accretion expense 4,211 2,774 2,904 3,041 12,930

(Gain) loss on abandonment 896 10,981 997 16 12,890

Impairment - 125,059 8,049 699 133,807

Noncash derivative loss (gain) (25,619) (27,411) (116) 17,797 (35,349)

Other - 192 - - 192

Consolidated EBITDAX 104,411 242,435 66,986 71,939 485,771



Appendix – Vendor Participation

As stated in Diamond Offshore’s June 3, 2009 rig status update:

Revised Ocean Victory Contract

On 22 May 2009 the Company entered into a drilling contract amendment with ATP Oil & Gas with

respect to

the

Ocean

Victory

in

the

Gulf

of

Mexico.

This

contract

was

amended

to

provide

that

for

a

minimum of the first 240 days of the initial one‐year period, the dayrate will be $560,000, $75,000 of

which will be paid in cash. The remaining dayrate of $485,000 will be payable from the proceeds of a

net profits interest granted pursuant to the operator's conveyance of an overriding royalty interest in

certain leases on which six contract development wells are expected to be drilled.

Payment of the proceeds pursuant to the overriding royalty interest is currently estimated to require

approximately one year after production on such wells begins. Such production is currently expected

to begin in late 2009 or early 2010. Payment of the remaining amounts, and the timing of such

payments, are contingent upon such production and upon commodity sale prices.

Remaining days

under

the

initial

one

‐year

contract

period

will

be

deferred

until

approximately

the

fourth quarter of 2011, when the contract provides that the rig will be utilized by the operator at a

dayrate of $540,000 payable in cash.

The appropriate accounting treatment for the deferrals is currently being determined.

│24│



Appendix – Hedge Schedule

│25│

3Q 4Q FY 1Q 2Q 3Q 4Q FY 1Q 2Q 3Q 4Q FY

Gulf of Mexico

Fixed Forwards & Swaps

Natural Gas

Volumes (MMMBtu) 1,912 1,912 3,824 1,800 90 5 910 91 0 4,525 Price ($/MMBtu) 4.70$ 4.93$ 4.81$ 5.37$ 5.73$ 5.73$ 5.73$ 5.58$

Crude O il

Volumes

(MBbls) 305

460

765

450

45 5

184

18 4

1,273

90

91

181

Price ($/Bbl) 67.60$ 67.60$ 67.60$ 67.60$ 67.60$ 70.00$ 70.00$ 68.29$ 72.00$ 72.00$ 72.00$ Reparticipation calls ($ /Bbl) 97 .5 0$ 97.50$ 97.50$ 97.50$ 97.50$ 110.00$ 110.00$ 101.11$ 115.00$ 115.00$ 115.00$

Collars

Natural Gas

Volumes (MMMBtu) 460 460 920 450 1,365 1,380 1,380 4,575 1,350 1,350 Floor Price ($/MMBtu) 4.00$ 4.00$ 4.00$ 4.00$ 4.75$ 4.75$ 4.75$ 4.68$ 4.75$ 4.75$ Ceiling Price ($/MMBtu) 7.00$ 7.00$ 7.00$ 7.00$ 7.95$ 7.95$ 7.95$ 7.86$ 7.95$ 7.95$

Puts

Crude O il

Volumes (MBbls) 460 460 920 90 91 92 92 365 Floor Price ($/Bbl) 29.75$ 29.75$ 29.75$ 24.70$ 24.70$ 24.70$ 24.70$ 24.70$

North Sea

Fixed Forwards & Swaps

Natural Gas

Volumes (MMMBtu) 759 759 270 27 3 276 27 6 1,095 Price

($/MMBtu)(1) 6.51$

6.51$ 7.27$

7.27$

7.27$

7.27$

7.27$

Collars

Natural Gas

Volumes (MMMBtu) 450 45 5 460 46 0 1,825 270 270 Floor Price ($/MMBtu)

(1)6.28$ 6.28$ 6.28$ 6.28$ 6.28$ 6.28$ 6.28$

Ceiling Price ($/MMBtu)(1)

9.42$ 9.42$ 9.42$ 9.42$ 9.42$ 9.42$ 9.42$ The above are ATP's outstanding financial and physical commodity contracts.

Additional hedges,

derivatives

and

fixed

price

contracts,

if any,

will

be

announced

during

the

year.

(1) Assumes USD $1.65 to GBP 1.00 currency translation rate.

2009 2010 2011



Note: based on independent third‐party reservoir engineers a t December 31, 2008.

ATP’s Five Year Reserve Growth and Performance

│26│

-

50

100

150

200

250

2004 2005 2006 2007 2008

N

e t M M B o e

CumulativeProduction

Asset Sales

Probable

Proved



Since the

focused

move

to

deepwater

in

2004,

ATP

has

added

119

million

Boe

(57% oil) in Proved Reserves

Growth in Reserves

With the move to deepwater, revisions, extensions and discoveries has

increased from

3%

of

reserve

growth

to

57%

Acquisitions

45

MMBoe(97%)

Revisions, extensions and

discoveries 1 MMBoe (3%)

2000 ‐2004 2004 ‐2008

Acquisitions

51 MMBoe

(43%)

Revisions,

extensions

and

discoveries

68 MMBoe

(57%)

│27│

Shelf ‐focused Deepwater‐focused



August 2006 Estimate of Additional Reserves

60 MMBoe

68 MMBoe

Probable - 18 MMBoe

Proved- 40 MMBoe

Produced-10 MMBoe

Evaluated bythird-party

reservoir engineers

│28│

At the EnerCom Oil & Gas Conference in August 2006, ATP estimated an additional 60

MMBoe (360 Bcfe) of additional reserves not reflected in third‐party reserve reports

By year‐end 2007 over 114% of these estimates had been produced or included by

ATP’s third‐party engineers in proved and probable reserves

Management estimates of additional

reserves at August 2006

Actual 12/31/07

18 months



J uly 2008 Estimate of Additional Reserves

47 MMBoe (62%)

booked by third‐

party reservoir

engineers in Proved

and Probable

Reserves at

12/31/08

Management

estimates

of

additional

reserves at July 2008 Actual

12/31/08

76 MMBoe

At the

EnerCom

Oil

&

Gas

Conference

in

August

2008,

ATP

announced

an

additional

76

MMBoe not reflected in third‐party reserve reports

After only 6 months ATP has already booked 62% of the management estimate in

Proved and Probable Reserves

29 MMboe (38%)

estimate under

evaluation

6 months

│29│

Documents

Aug2009 ATP Presentation