Coastal Annual 2011

7/25/2019 Coastal Annual 2011

1/641

A N N U A L R E P O R T2 0

1 1

T H E P AT H T O

P E R F O R M A N C E


2/642

2 Presidents Report to the Shareholders

4 Financial and Operational Highlights

12 Managements Discussion and Analysis

26 Managements Report

27 Independent Auditors Report

28 Consolidated Statements of Operations and Comprehensive Income

29 Consolidated Statements of Financial Position

30 Consolidated Statements of Cash Flows

31 Consolidated Statement of Changes in Equity

32 Notes to the Consolidated Financial Statements

61 Corporate Information

T a b l e o f C o n t e n t s


3/641

A D D I N GR E S E R V E S .

D E L I V E R I N GR E S U L T S .

Drilling exclusively in Thailand, Coastal Energy achieved

record revenues in 2011 while increasing certied 2P

reserves by more than 100%.

AV E R A G E D A I LY

P R O D U T I O N V O L U M E

In boe/d


4/642

Dear Fellow Shareholders:

Increased production and higher oil prices enabled

Coastal Energy to achieve its best-ever nancial results

in 2011, while successful appraisal and development

wells bolstered the companys year-over-year certied

2P reserves by 101%. Financial highlights included

an 80% increase in crude oil revenues and a 77%

increase in EBIDTAX (earnings before interest, taxes,

depreciation, depletion, amortization and exploration

expenses).

These results demonstrate short-term success and suggesta sustainable path to performance. With approximately

three years of drilling prospects and production from the

recently discovered Bua Ban North eld still in an early

phase, we have reasons to be optimistic.

Our unique position

The Coastal success story attracted a number of new

shareholders during 2011. While results will vary

quarter by quarter, we believe our unique positioning

will continue to provide Coastal advantages:

We focus exclusively on Thailand, which provides astable operating environment and offshore properties

with prospects for signicant oil reserves. Currently,

we have 1.4 million acres leased in the Gulf of

Thailand and more than 30 prospects identied.

Coastals offshore production and prospects are in

shallow water, making for cost-effective development.

With approximately 70% of outstanding shares owned

by management and four top shareholders, we are

motivated to succeed.

Like other young E&P companies, one of our early goals

was to fund exploration with current cash ow. Im

pleased to say we met that goal in 2011. A signicant

factor in reaching this milestone is our ability to quickly

commercialize new discoveries. Typically, its a matter

of just a few months to turn development production

into cash ow. Barring any unforeseen circumstances,

our 2012 exploration program will be entirely self-

funded and the Company will be able to reduce its debt

balances and put cash on the balance sheet.

Offshore

Production highlightsFor the year, Coastal produced 3.56 million barrels of

oil (mmbl). By year end, oil production from three elds

Bua Ban North, Songkhla Field and Bua Ban was

averaging 16,200 barrels of oil per day (bopd), up from

10,500 bopd at the beginning of 2011.

The highlight was Bua Ban North, which began

production in August after its discovery early in

the year. By year end, it was generating 69% of the

companys total output. The Bua Ban North properties

bolstered our total Company 2P reserves by 132%.

Exploration highlights

Signicant oil reserves in the Miocene sands at Bua

Ban North were proven with exploration wells at two

separate prospects. Those prospects Bua Ban North

A and Bua Ban North B were later proved to be

connected to one another. Third-party reserve estimates

of 67 mmbl at Bua Ban North make it the companys

most successful discovery.

Offshore oil production

topped 3.5 million

barrels in 2011.

2


5/64

Onshore

Coastals onshore interests are held indirectly through

an equity investment in Apico LLC. Production and

revenues from Apico gas elds in northeastern Thailand

increased during the year, however, severe ooding in

the third and fourth quarter caused demand to decrease.

At year end, Coastals share of onshore production was

approximately 1,360 barrels of equivalent per day (boe/d)

average, with 2P reserves of 24 mmboe. In early 2012,

Coastal purchased additional shares in Apico and now

owns 39% of the company.

Operational highlights

Coastal is a safe and efcient operator. Once again, we

are very pleased to report zero reportable HSE (health,

safety, environmental) issues during the year. Meanwhile,

our average cost of $3.0 3.5 million for drilling wells in

the Miocene sands is extremely competitive. Protability

of oil sales was also improved with a new two-year

agreement to sell crude at a higher percentage of the

Dubai benchmark price. That agreement went into effect

in January 2012.

Whats ahead in 2012

A $235 million capital budget will include $130 million

for drilling. Approximately 60% of the drilling budget wil

be devoted to exploration and 40% to development. The

exploration focus will be on multiple Miocene prospects

throughout the basin aiming to build upon the successful

Miocene discoveries at Bua Ban North. Additional

horizontal development wells are planned in Bua Ban

North to increase production and total recovery. In the

Songkhla A eld we will drill ve to seven appraisal/

development wells to exploit areas of the reservoir

discovered in 2010. Onshore will also see activity, withthe potential to market gas discovered in early 2012

during the sidetrack of the Dong Mun 3 well.

Realistic expectations go hand in hand with the

experience of our management and staff. We know that

2011 was an exceptional year for Coastal. Even so, we are

hopeful for similar results in 2012, and I believe we have

the prospects and abilities to make that happen.

On behalf of the Board of Directors

Randy L. Bartley

President and Chief Executive OfcerMarch 28, 2012

T O T A L A N N U A L

E B I T D A X

EBITDAX - US $000s

O P E R A T I N G C A S H F L O W

P E R S H A R E

Cash Flow per Share - US $000s

1.63

2011

0.87

2010

0.55

2009

0.03

2008

201,689

2011

114,271

2010

37.864

2009

5,925

2008


6/644

THAILAND

LAOS

CAMBODIA

BURMA

GULF

OF

THAILAND

Block G5/50

Block G5/43

Songkhla Field

Bua Ban FieldSONGKHLA

SURAT THANI

Bangkok

L 15/43

L 13/48

Sinphuhorm Gas Field

12.6% WI

L 15/43

36.1% WI

Dong Mun Gas Field

36.1% WI

Si That Gas Field

21.7% WI

L 27/43

Coastal Energys Oil & Gas Interests

4

F I N A N C I A L A N D O P E R A T I O N A L H I G H L I G H T S

Years Ended

December 31, 2011 and 2010


7/645

3 months ended December 31, Years ended December 31,

2011 2010%

Change 2011 2010%

Change

F I N A N C I A L

Crude oil revenue $128,929 $33,246 288% $347,783 $193,608 80%

EBITDAX (1)

Per share Basic $0.66 $0.03 - $1.80 $1.04 73%

Per share Diluted $0.64 $0.03 - $1.74 $1.04 67%

Net Income (loss)

Per share Basic $0.17 $(0.56) - $0.42 $(0.12) -

Per share Diluted $0.16 $(0.56) - $0.41 $(0.12) -

Capital expenditures, excluding onshore $44,614 $27,625 61% $153,535 $144,749 6%

Total Assets $518,731 $368,942 41%

Working capital decit $48,848 $58,953 -17%

Weighted average common shares outstandingBasic 112,998,419 109,627,720 3% 112,226,944 109,451,113 3%

Diluted 117,849,003 109,627,720 7% 115,994,340 109,451,113 6%

O P E R A T I O N S

Operating netback ($/bbl) (1) (2)

Crude oil revenue $101.05 $76.66 32% $101.39 $70.47 44%

Royalties 9.37 6.39 47% 8.49 5.97 42%

Production expenses 25.69 41.50 -38% 28.94 19.41 49%

Operating netback $65.99 $28.77 129% $63.96 $45.09 42%

Average daily crude oil production (bbls)(2) 13,386 5,557 141% 9,760 7,653 28%

Notes:(1)Non-IFRS measure; see Non-IFRS Measures section within MD&A.(2)Includes offshore crude oil only as onshore is accounted for using the equity method of accounting.

F I N A N C I A L A N D O P E R A T I O N A L H I G H L I G H T S


8/646

Fourth Quarter 2011 Highlights

Total Company production increased to 14,508 boe/d in

the fourth quarter from 7,552 boe/d in the same period

last year. The Companys offshore production was

bolstered by the inclusion of a full quarter of production

from the B platform at the recently discovered Bua Ban

North eld. The Company began tying in production

at Bua Ban North A late in Q4 and realized production

gains from that eld beginning in 2012. Productionat Songkhla A and Bua Ban Main was in line with

expectations. Average onshore production was 1,122

boe/d, impacted by decreased demand due to the severe

ooding in Thailand in Q3 and Q4 2011. Demand has

made a signicant recovery in 2012.

EBITDAX for the full year of 2011 was $201.7 million,

77% higher than the $114.3 million recorded in 2010.

Revenue and EBITDAX were driven higher by

increased production and commodity prices. Crude oil

inventory was approximately 336,000 barrels at year

end, the revenue from which will be recognized in 2012.

The Company announced that RPS Energy, Ltd.

delivered a third party reserves evaluation of Bua

Ban North A & B. The report assigned 54.9 mmbbl of

reserves to 1P and 67.0 mmbbl to 2P. The report also

assigned 63.0 mmbbl of contingent and prospective

resources to the area.

The Company announced several successful appraisal

and development wells at the Bua Ban North A &

B platforms. These wells helped to further delineate

the eld and conrm that the two elds are in factconnected. One horizontal well was drilled during the

quarter and began producing at a rate of approximately

3,000 bopd. The Company plans to drill several more

horizontal development wells at the eld to increase

production and total recovery.

The following chart represents the Companys Average

BOE/D on a quarterly basis

Q1 10 Q2 10 Q3 10 Q4 10 Q1 11 Q2 11 Q3 11 Q4 11

Onshore Songkhla Bua Ban Main Bua Ban North

16,000

14,000

12,000

10,000

8,000

6,000

4,000

2,000

0

Q U A R T E R L Y P R O D U C T I O N

(boe/d)

1,855

7,068

1,900

7,914

1,730

6,922

3,143

2,024

3,502

2,041

1,926

6,384

1,815

2,291

5,785

1,418

1,868

3,958

1,403

4,830

1,122

5,247

1,234

6,905

Note:Bua Ban North came onstream starting in August 2011

The following chart represents the Companys cash

operating netback ($/bbl) for its offshore production over

the past eight (8) quarters. Operating netback is based on

sales volume and is a non-IFRS measure. See Non-IFRS

and Non-GAAP Measure section within the MD&A.

Q1 10 Q2 10 Q3 10 Q4 10 Q1 11 Q2 11 Q3 11 Q4 11

Cash Operating Netback Production Expense Royalties Cash Taxes

120.00

100.00

80.00

60.00

40.00

20.00

0.00

48.8853.17

44.78

28.77

58.19

71.19

60.83

65.9915.42

5.12

14.18

5.45

15.79

6.6841.50

6.39 29.06

7.6428.69

8.41

34.25

7.94

25.69

9.37

O P E R A T I N G N E T B A C K S

($/bbl)


9/647

EBITDAX Computation

2011 2010

Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1

Net income (loss) attributableto shareholders $18,892 $19,013 $11,816 $(2,362) $(62,741) $25,077 $12,526 $11,568

Add Back:Unrealized loss (gain) on

derivative 3,663 (15,019) (7,744) 18,257 16,614 - 1 65Realized loss on

derivative (c) 5,175 3,837 8,615 2,400 1,567 - - -

Interest income (2) (2) (1) (1) (1) (1) (1) (2)

Stock option expense 677 587 607 618 545 615 676 683Unrealized foreign

exchange loss / (gain) (b) 268 (337) 308 149 297 2,158 (121) (135)

Interest expense 1,549 913 1,201 1,162 1,272 722 749 732

Debt nancing fees 273 258 31 234 256 23 119 124(Gain ) loss on sale of

assets - (873) - - - - - -Depletion, depreciation and

accretion 22,844 13,308 11,698 13,286 11,658 8,343 3,684 5,973

Taxation 20,201 22,628 12,005 3,183 (40,857) 9,872 12,669 6,541Impairment and Settlement

expense - - - - 10,706 - - -Exploration 1,545 345 931 5,553 62,786 26 91 9,267

Other IFRS transition - - - - 2,311 (2,327) (539) 680

EBITDAX $75,085 $44,658 $39,467 $42,479 $4,413 $44,508 $29,854 $35,496

Notes:(a) Not used(b) The unrealized foreign exchange adjustment primarily relates to a tax liability in Thailand and is not expected to be a cash item.(c) The realized loss on the derivative contracts has been added back to net income / loss since these contracts were executed as part

of the debt facility with BNP Paribas and therefore considered a nancing cost. This has lead to a revision of the Q4 2010 and Q12011 EBITDAX numbers. EBITDAX is a non-GAAP/non-IFRS measure.

The following chart represents the Companys EBITDAXon a quarterly basis in US$000s

Q1 10 Q2 10 Q3 10 Q4 10 Q1 11 Q2 11 Q3 11 Q4 11

80,000

70,000

60,000

50,000

40,000

30,000

20,000

10,000

0

E B I T D A X

(US $000s)

35,496

29,854

44,508

4,413

42,47939,467

44,658

75,085


10/648

The forecasted prices used by RPS Group Ltd. in their

evaluation for December 31, 2011 were taken from

RPSs own internal estimates of future commodity prices.

Forecasted prices as at December 31, 2011 and December31, 2010 are as follows.

Year

Oil as at

December 31,2011

($/bbl)

December 31,2010

($/bbl)

December 31,2009

($/bbl)

2010 n/a n/a 72.59

2011 n/a 82.76 76.59

2012 105.80 82.51 79.59

2013 101.30 82.76 82.59

2014 96.80 84.76 85.59

2015 96.61 87.93 87.432016 98.63 90.31 89.31

2017 100.69 93.02 91.23

2018 102.79 95.50 93.18

2019 104.93 97.41 95.17

2020 107.11 99.36 n/a

thereafter 2.1% 2.0% 2.0%

The following table summarizes the present value of future

net revenues discounted at 10% before income taxes at

December 31, 2011 and 2010.

US $ millions based on forecastedprices at December 31, 2011 2010

Proved Reserves:

Developed producing $1,182.3 $319.3Developed non-producing 852.1 44.1

Undeveloped 874.5 254.7

Total Proved Gulf of Thailand $2,908.9 $618.1

Total Probable Gulf of Thailand $506.5 $571.4

Total Proved Plus Probable Gulfof Thailand $3,415.4 $1,189.5

Thailand Onshore

RPS also evaluated the onshore reserves held via Apico

effective December 31, 2011. Selected data from RPSs

report follows.

Natural gas is converted to equivalent barrels (BOE)

at the energy equivalent conversion rate of six thousand

cubic feet (6mcf) to one barrel (1bbl) of crude oil,

reecting the approximate relative energy content. The

following reserve gures, before royalties for 2011 and

2010 reect Coastal Energys 36.1% interest in APICO as

if the Company directly owned the onshore properties.

Oil and Gas Reserves

The Companys oil and gas assets are all in Thailand and

are divided into two groups Gulf of Thailand properties,

which are held directly by the Company; and Thailand

Onshore properties, which are held indirectly though

the Companys equity investment in Apico. Therefore,

in accordance with Canadian securities regulations,

the following reserves information has been reported

separately for the two groups.

Gulf of Thailand Properties

The Companys Gulf of Thailand reserves were evaluated

by RPS Energy, Ltd. (RPS) effective December 31,

2011. Selected data from their report follows. Their report,

dated March 28, 2011, is available on SEDAR at www.

sedar.com. Natural gas is converted to equivalent barrels

(BOE) at the energy equivalent conversion rate of six

thousand cubic feet (6mcf) to one barrel (1bbl) of crude

oil, reecting the approximate relative energy content. The

following reserve gures, before royalties for 2011 and

2010 reect Coastal Energys 100% interest in its Gulf of

Thailand concessions (Block G5/43 and G5/50.)

Gulf of ThailandOil and Gas Reserves (Gross)

December 31, 2011 December 31, 2010

Oil(Mbbls)

Gas(MMcf)

BOE(Mbbls)

Oil(Mbbls)

Gas(MMcf)

BOE(Mbbls)

Proved Reserves

Developed producing 25,115 25,115 9,552 - 9,552Developed non-producing 17,638 17,638 687 - 687

Undeveloped 19,736 19,736 4,250 - 4,250

Total Proved 62,489 - 62,489 14,489 - 14,489

Total Probable 17,453 - 17,453 12,654 - 12,654

Total Proved Plus Probable 79,942 - 79,942 27,143 - 27,143

O P E R A T I O N A L R E V I E W


11/649

Thailand OnshoreOil and Gas Reserves (Gross)

December 31, 2011 December 31, 2010

Oil(Mbbls)

Gas(MMcf)

BOE(Mbbls)

Oil(Mbbls)

Gas(MMcf)

BOE(Mbbls)

Total Proved 222.4 43,305 7,440 245 46,680 8,025

Total Probable 461.0 89,750 15,419 486 92,488 15,900

Total Proved Plus Probable 683.4 133,055 22,859 731 139,168 23,925

Year

As at December 31, 2011 As at December 31, 2010

Condensate($/bbl)

Gas($/Mcf)

Condensate($/bbl)

Gas($/Mcf)

2011 n/a n/a 79.12 7.35

2012 102.68 8.44 81.00 6.69

2013 98.44 8.13 81.94 6.75

2014 94.19 7.81 84.44 6.93

2015 94.03 7.80 86.16 7.05

2016 95.92 7.79 87.90 7.172017 97.86 8.08 89.67 7.15

2018 99.84 8.22 91.49 7.28

2019 101.85 8.37 93.34 7.40

2020 103.91 8.12 95.23 7.53

thereafter 2.0% 2.0% 2.0% 2.0%

The forecasted prices used by RPS Group Ltd. in their

evaluation for December 31, 2011 were taken from

RPSs own internal estimates of future commodity prices.

Forecasted prices as at December 31, 2011 and December

31, 2010 are as follows.

The following table summarizes the present value of future

net revenues discounted at 10% before income taxes at

December 31, 2011 and 2010.

US $ millions based on forecastedprices at December 31, 2011 2010

Total Proved Thailand Onshore $184.2 $165.0

Total Probable Thailand Onshore $158.6 $141.0

Total Proved Plus Probable Thailand Onshore $342.8 $306.0

Oil and Gas Properties

Summary of Oil & Gas PropertiesThailandOnshore Gulf of Thailand Totals

Balance, December 31, 2009 $55,225 $223,207 $278,432

Additions during the period, net of disposals:

Exploration & development - 156,519 156,519

Equity earnings in Apico, net of distributions (6,855) - (6,855)

Depletion - (30,911) (30,911)

Exploration expense - (72,170) (72,170)

Amortization of excess basis in Apico (1,109) - (1,109)


Additions during the period, net of disposals:

Exploration & development 1,446 176,655 178,101

Equity earnings in Apico, net of distributions 47 - 47

Depletion - (59,447) (59,447)

Exploration expense (8,374) (8,374)

Amortization of excess basis in Apico (1,056) - (1,056)



12/6410

Gulf of Thailand Properties

CAMBODIA

GULFOF

THAILAND

Block G5/50

Block G5/43

Songkhla Field

Bua Ban FieldSONGKHLA

SURAT THANI

Bangkok

i l.

Block G5/43 Songkhla Basin

The Company holds a 100% working interest in

Blocks G5/43 and G5/50 (the Blocks) in the Gulf of

Thailand. The current combined area of the Blocks is

approximately 5,021 square kilometres and average waterdepths are approximately 70 feet. Block G5/50 contains

approximately 554 square kilometers of acreage within the

boundaries of Block G5/43.

Bua Ban North Field

The Bua Ban North eld was discovered in 2011. It

was originally drilled as two separate prospects which

later proved to be connected to one another. The initial

exploration wells at both locations discovered signicant

amounts of oil in the Miocene interval. These discoveries

have proven the commercial viability of the Miocene trend

in the Songkhla basin.

The Company has drilled a total of 24 wells at the Bua Ban

North eld. To date, two horizontal development wells have

been drilled and each have had initial production rates of

2,500 3,000 bopd. Several more horizontal development

wells are planned to increase production and ultimate

recovery. The Company is planning further appraisal and

development drilling at Bua Ban North in mid-2012.

There are currently two production facilities at Bua Ban

North. Production at the B platform began in August

2011 and production at the A platform began at the rstof 2012. Approximately 12 additional development wells

and 1 water injector are required for full eld development

at Bua Ban North.

Production at Bua Ban North is currently averaging

16,600 bbl/d. As of December 31, 2011, Bua Ban North

had proven and probable (2P) reserves of approximately

67.9 million barrels of oil.

Bua Ban Main Field

Production from the eld commenced in July 2010. Two

of the wells, the A-03 and A-11, both encountered oil in

the Miocene reservoir. This was the rst time productive

Miocene sands had been encountered in the Songkhla

basin and laid the foundation for the successful Miocene

exploration at Bua Ban North in 2011. Production from

Bua Ban is currently averaging approximately 1,300

bbl/d. As of December 31, 2011, Bua Ban had proven andprobable (2P) oil reserves of 1.3 million barrels of oil.

Songkhla Field

The Songkhla A eld was the rst eld developed by the

Company beginning in 2008. The Company is currently

producing approximately 4,750 bbl/d at the Songkhla

A eld. Further appraisal and development drilling is

scheduled for 2012. One development well and two water

injectors are required to exploit the eastern area of the

reservoir which was discovered in 2010. The Company is

awaiting written environmental approval for these wells.

As of December 31, 2011, Songkhla A had proven and

probable (2P) reserves of approximately 9.9 million

barrels of oil.

In the third quarter of 2011 and in compliance with the

terms of the concession, the Company drilled an exploration

well at Songkhla H. This well was successful but could not

be completed due to being outside the current production

licenses. The Company intends to le for another production

license to encompass this eld. As of December 31, 2011,

Songkhla H had proven and probable (2P) reserves of

approximately 0.8 million barrels of oil.

Under the terms of the concession agreement and the Thai

Petroleum Act B.E. 2514, the Company is required to

periodically relinquish a portion of its concession which is

not protected under the Companys production licenses.

The following table shows the size of the initial concession,

all relinquishments made by the Company and the

remaining size with respect to Block G5/43.

Activity Date

Size inSquare

KilometersInitial grant of the concession 17 July 2003 17,110End of concessions rst

exploration period (~50%) 17 July 2007 (8,615)End of concessions second

exploration period (~25%) 17 July 2009 (4,028)

4,467


13/6411

Company management used available seismic and

technical data to determine the less prospective acreage

which was relinquished. The Company incurred a $1.5

million charge in the fourth quarter of 2011 related to

the relinquishment of 50% of G5/50 acreage. The 50%

relinquished was deemed to not have any basinal qualities

following seismic interpretation. At December 31, 2011,

total Gulf of Thailand 2P reserves are 79.9 million barrels

of oil (before royalties).

Thailand Onshore

THAILAND

LAOS

CAMBODIA

BURMA

l

l

l i l

i l

Bangkok

L 15/43

L 13/48

Sinphuhorm Gas Field

12.6% WI

L 15/4336.1% WI

Dong Mun Gas Field36.1% WI

Si That Gas Field21.7% WI

L 27/43

The Companys Thailand onshore interests are held

indirectly through its equity investment in Apico. Apico

is considered a signicantly inuenced investee. Apicos

petroleum concessions are located in the Khorat Plateau

in north eastern Thailand. Apicos results of operations

for the years ended December 31, 2011 and 2010 and its

nancial position are as follows:

Apico Results for the yearended December 31, 2011 2010

Total revenue $86,625 $71,493

Total expenses 17,166 25,082

Income tax expense 26,326 21,388

Net Income $43,133 $25,023

Apico Balance Sheet as ofDecember 31, 2011 2010

Current assets $19,419 $22,969

Property, plant andequipment 108,956 112,618

Other assets 777 3,105

Total assets $129,152 $138,692

Current liabilities $30,694 $28,903

Non-current liabilities 2,731 9,815

Members equity 95,727 99,974

Total liabilities and equity $129,152 $138,692

Coastal holds a net working interest of 13.7% (12.6% at

December 31, 2011) in Blocks EU-1 and E-5N onshore

Thailand through its 39.0% (36.1% at December 31, 2011)

equity investment in Apico, LLC, which holds a 35% non-

operated working interest in the Blocks. Blocks EU-1

and E-5N contain the Sinphuhorm gas eld. Production

at Sinphuhorm commenced on November 30, 2006 to

supply the Nam Phong power plant with over 500 billion

cubic feet of gas, plus condensate, under a 15 year GasSales Agreement with PTT Public Company Limited. In

the fourth quarter of 2011, the Sinphuhorm eld delivered

approximately 52.4 mmcf/d (6.6 mmcf/d net to Coastal) to

Nam Phong. The eld also produced 251 bbl/d (32 bbl/d

net to Coastal) of condensate. The lower volume in the

fourth quarter was due to decreased industrial demand

as a result of the severe ooding in Thailand in the third

and fourth quarters of 2011. In early 2012, demand has

begun to accelerate as factories are returning to full

production and the country is rebuilding. The Company

acquired an additional 2.9% of Apico in the rst quarter

of 2012, bringing its total ownership interest to 39%. As

of December 31, 2011, Sinphuhorm had 2P reserves of

963 billion cubic feet (bcf) of natural gas (131 bcf net to

Coastal, 22.2 mmboe) and 5 mmbbls of oil (0.7 mmbbls net

to Coastal), before royalties.

Coastal also holds a net 39.0% (36.1% at December

31, 2011) working interest in Block L27/43 (operated

by Apico), which is located southeast of the L15/43

concession. A sidetrack of the Dong Mun 3 well drilled

in Q1 2012 encountered a 113 meter gas column with

commercial degrees of porosity and permeability. The wellowed 15 mmcfd of gas when tested. Further wells will be

required to determine the areal extent of the Dong Mun

prospect. The Company and its partners are currently

evaluating a marketing plan for the gas to commercialize

this prospect.

The Company has a net 39.0% (36.1% at December 31,

2011) working interest in Block L15/43 (operated by

Apico), which surrounds the Sinphuhorm gas eld.

Effective January 1, 2012, the Company purchased an

additional 2.9% of Apico from a minority partner for $9.25million cash, bringing Coastals interest in Apico to 39.0%.


14/6412

The following is Managements Discussion and Analysis

(MD&A) of the results and nancial condition of

Coastal Energy Company (Coastal or the Company).

This MD&A, dated March 28, 2012, should be read in

conjunction with the accompanying audited consolidated

nancial statements as at and for the three and twelve

months ended December 31, 2011 and related notes

thereto. Additional information related to the Company is

available on SEDAR at www.sedar.com.

Overview

The Company was incorporated under the Companies

Law of the Cayman Islands on May 26, 2004. The

Company is engaged in the acquisition and exploration of

petroleum and natural gas properties in Southeast Asia.

The functional and reporting currency of the Company

and its subsidiaries is the US dollar. The Companys

trading symbols are CEN on the TSX and CEO on the

AIM exchange.

The Companys oil and gas properties and assets consist of

the following ownership interests in petroleum concessions

awarded by the Kingdom of Thailand as of December 31,

2011:

M A N A G E M E N T S D I S C U S S I O N A N D A N A L Y S I S

Petroleum ConcessionCoastals

Working Interest

Gulf of Thailand

Block G5/43 100.0%

Block G5/50 (within the boundaries of Block G5/43) 100.0%

Onshore Thailand (via Coastals 36.1% ownership of Apico LLC (Apico))

Blocks EU-1 and E-5N containing the Sinphuhorm gas eld 12.6%

Block L15/43 (surrounding the Sinphuhorm gas eld) 36.1%

Block L27/43 (southeast of the Sinphuhorm gas eld) 36.1%

Non-IFRS and Non-GAAP Measures

This report contains nancial terms that are not

considered measures under International Financial

Reporting Standard principles (IFRS) or Canadian

Generally Accepted Accounting Principles (GAAP),

such as funds ow from operations, funds ow per share,

EBITDA, EBITDAX, net debt, operating netback and

working capital. These measures are commonly utilized

in the oil and gas industry and are considered informative

for management and shareholders. Specically, funds

ow from operations and funds ow per share reect

cash generated from operating activities before changes

in non-cash working capital. Management considers

funds ow from operations and funds ow per share

important as they help evaluate performance and

demonstrate the Companys ability to generate sufcient

cash to fund future growth opportunities and repay debt.

EBITDA is dened as earnings before interest, taxes,depreciation, amortization and earnings from signicantly

inuenced investee adjusted for non-cash items such as

unrealized gains and losses on risk management contracts,

unrealized foreign exchange gains or losses and Share-

Based Compensation. EBITDAX is an industry measure

equivalent to EBITDA but for the fact that it neutralizes

the impact of some companies expensing rather than

capitalizing exploration costs. Net debt includes short

term and revolving credit facilities less cash and cash

equivalents and restricted cash, and is used to evaluate

the Companys nancial leverage. Protability relative to

commodity prices per unit of production is demonstrated

by an operating netback. Working capital represents

current assets less current liabilities.

Funds ow from operations, funds ow per share,

EBITDA, EBITDAX, net debt, operating netbacks

and working capital are not dened by IFRS or GAAP,

and consequently are referred to as non-IFRS or non-

GAAP measures. Accordingly, these amounts may not be

compatible to those reported by other companies where

similar terminology is used, nor should they be viewed as

an alternative to cash ow from operations, net income

or other measures of nancial performance calculated in

accordance with IFRS or GAAP.

Forward Looking Statements

Certain information included in this discussion may

constitute forward-looking statements. Forward

looking statements are based on current expectations,

estimates, and projections that involve various risks and

uncertainties. These risks and uncertainties could cause

or contribute to actual results that are materially different

from those expressed or implied.


15/6413

Average Daily Production (boe/d)

3 Months ended

December 31,

Years ended

December 31,

2011 2010 Change 2011 2010 Change

Songkhla 5,247 3,509 50% 5,336 6,345 -16%

Bua Ban Main 1,234 2,048 -40% 1,466 1,308 12%

Bua Ban North 6,905 - - 2,958 - -

Total Offshore Production 13,386 5,557 141% 9,760 7,653 28%

Sinphuhorm (via Apico) 1,122 1,995 -44% 1,780 2,017 -12%

Total Company 14,508 7,552 92% 11,540 9,670 19%

Fourth quarter offshore production increased signicantly

from the prior year period due to the inclusion of a

full quarter of production at the Bua Ban North B

platform. Fourth quarter production at Bua Ban North

was approximately 6,900 bopd, which was below the

third quarter exit rate of 8,000 bopd due to downtime in

November and December as the rig was mobilized anddemobilized to and from the location, and certain wells

had to be shut in during this process. Songkhla production

returned to more normalized levels in the fourth quarter

following the installation of additional cooling units at the

Songkhla platform to mitigate a temperature issue with the

oil transfers. Production at the Bua Ban Main platform

was slightly below levels in the same period as last year.

Production at the Bua Ban North A platform began in

early 2012.

The Company is planning to drill further appraisal and

development wells at Bua Ban North in 2012, including

several horizontal development wells to increase

production further as well as injection wells to maintain

aquifer support. Further appraisal and development wells

are also planned at Songkhla to boost production and

appraise some of the areas discovered by the Q4 2010drilling campaign.

Onshore production was negatively impacted in Q4 due

to decreased demand as a result of the severe ooding in

Thailand in late 2011. Demand has begun to increase in

early 2012 as factories have returned to production and the

country has begun its rebuilding efforts.

The following table reconciles the Companys offshore

inventory, production and liftings.

Crude Oil Inventory (bbls)

3 Months endedDecember 31,

Years endedDecember 31,

2011 2010 Change 2011 2010 Change

Inventory Beginning of Period 380,754 126,209 202% 203,983 157,883 29%

+ Production 1,231,488 511,432 141% 3,562,408 2,793,644 27%

- Sales / Liftings (1,275,908) (433,658) 194% (3,430,057) (2,747,544) 25%

Inventory, End of Period 336,334 203,983 65% 336,334 203,983 65%

The Companys crude oil production is stored in oating

storage and ofoading vessels (FSOs) moored at the

production platforms. The inventory represents crude

oil produced and loaded in the FSOs, but which had

not yet been off-loaded for sale at the end of the period.

The Company ended the year with over 336,000 bbl in

inventory, the revenue and associated expenses of which

will be recognized in 2012.

Financial Review

The following tables are analysis of the line items in the

Companys Consolidated Statements of Operations and

Comprehensive Loss and are comparisons of the current

quarter activities vs. the same quarter in the prior year,

unless otherwise noted.

Oil Sales, Average Benchmarkand Realized Prices ($/bbl)

3 Months ended

December 31,

Years ended

December 31,

2011 2010 Change 2011 2010 Change

Oil Sales $128,929 $33,246 288% $347,783 $193,608 80%

Dubai (Benchmark - $/bbl) $106.50 $84.39 26% $106.31 $78.12 36%

Sales Price per bbl Sold ($/bbl) $101.05 $76.66 32% $101.39 $70.47 44%

Sales Price as a Percentage of Dubai 95% 91% 95% 90%


16/6414

Revenue increased dramatically in Q4 over the same

period in 2010, driven by signicantly higher production

and lifting volumes as well as a 32% increase in realized

pricing. The Company had over 336,000 bbl of crude oil

inventory at quarter end, the revenue from which will be

recognized in 2012. This was a decrease from the 380,000

bbl which were in inventory at the beginning of the

quarter and an increase from the 204,000 bbl which were

in inventory at the end of Q4 2010.

The sales price for the Companys offshore oil is based on

the Dubai benchmark price. The Company is receiving

a higher percentage of its benchmark crude price as

it retendered for bids for the crude offtake contract.

In the fourth quarter of 2011, the Company signed a

2-year agreement to sell its crude oil at a xed $1.75

per bbl discount to Dubai pricing. This price includes

transportation costs.

Royalties

3 Months ended

December 31,

Years ended

December 31,

2011 2010 Change 2011 2010 Change

Royalties $11,955 $2,769 332% $29,113 $16,401 78%

$ per bbl $9.37 $6.39 47% $8.49 $5.97 42%

Royalties as a percent of revenue 9.3% 8.3% 8.4% 8.5%

Royalties on the Gulf of Thailand assets are paid to

the Kingdom of Thailand as a percentage of revenue

calculated on a sliding scale and based on monthly sales.

Fourth quarter royalty rates increased in the fourthquarter both on a percentage basis and on a per barrel

basis due to higher lifting volumes and commodity prices,

respectively. Average annual royalty rates were at as

higher rates in last four months of 2012 year, due to

increased production, were offset by lower rates in the rsteight months on a dollar per barrel basis.

Other income

3 Months ended

December 31,

Years ended

December 31,

2011 2010 Change 2011 2010 Change

Unrealized gain (loss) on derivativecontracts $(3,663) $(16,614) - 843 $(16,681) -

Realized loss on derivative contracts (5,175) (1,567) - (20,027) (1,566) -

Interest income 2 1 - 6 5 -

Foreign exchange loss (336) (1,012) - (2,388) (1,064) -

Other - 99 - - 99 -

Other income $(9,172) $(19,093) - $(21,566) $(19,207) -

The Company has risk management contracts outstanding

to hedge its exposure to interest rate and commodity

price movements. These contracts were entered into as a

condition of the Companys revolving credit facility. The

Company adjusts the fair value of this risk management

contract (mark to market) every quarter with the changes

in fair value recognized in net earnings, as required under

IFRS. Volatility in commodity pricing has translated into

large swings in the Companys mark to market gains and

losses. The Company realized losses of $5.2 million in thefourth quarter, which was an increase from prior quarters

due to an increase in commodity pricing.

The net derivative liability at December 31, 2011 may

never be realized depending upon commodity price

movements between December 31, 2011 and expiry of the

nal contract (March 2013).

During the fourth quarter, the Company extended its

hedging contracts in accordance with the debt facility

agreement by adding approximately 800,000 bbl of

production hedged via a $70.00 / bbl purchased put and a

$119.10 / bbl sold call. This was a zero cost transaction for

the Company. The collar runs from October 2011 through

March 2013. The reference instrument is ICE Brent crude.

The Company has earned negligible income on its cash

balances due to the low global interest rate environment

for risk-free assets and by using cash on hand as part of its

capital intensive drilling program.

The foreign exchange loss is a result of the Companycarrying out transactions and maintaining certain

nancial assets and liabilities in currencies other than

the US Dollar. The primary foreign currency in which

the Company transacts is Thai Baht. The Company also

occasionally has transactions denominated in the Canadian

Dollar, Singapore Dollar, British Pound and Euro.

Included within the forex loss for the three and twelve

months ended December 31, 2011 is unrealised losses

associated with cash retranslation of $1.3m and $1.8m,

respectively.


17/6415

Production

3 Months ended

December 31,

Years ended

December 31,

2011 2010 Change 2011 2010 Change

Production expenses $31,445 $22,692 39% $101,034 $57,397 76%

Effect of change in inventory 1,328 (4,696) -128% (1,771) (4,071) -56%

$32,773 $17,996 82% $99,263 $53,326 86%

$ per bbl $25.69 $41.50 $28.94 $19.41

The year over year increase in fourth quarter productionexpenses was driven by inclusion of a full quarter of Bua

Ban North operating expenses of approximately $10.9

million, workover costs of $2.4 million and, to a lesser

extent, general oileld price ination. Fourth quarter

operating costs declined signicantly on a per barrel basis

due to the production gains from Bua Ban North. Coastal

expects per barrel costs to continue declining in coming

quarters due to further production gains from Bua Ban

North over a relatively xed lease operating cost base.

Year over year production costs increased due to the

inclusion of a full year of operating costs at Bua Ban Mainand ve months of operating costs at Bua Ban North.

Repair & maintenance expense due to storm damage ($2.8million) and increased workover expenses ($10.9 million)

also contributed to the overall increase. The Company

experienced an increase in operating costs on a per barrel

basis, primarily due to an overall increase in costs and

production declines at Songkhla and Bua Ban Main. The

addition of production from Bua Ban North has begun

to decrease per barrel operating costs, as evidenced by

fourth quarter per barrel costs coming in below full year

per barrel costs. Coastal expects this trend to continue in

coming quarters.

General and Administrative Expenses

3 Months ended

December 31,

Years ended

December 31,

2011 2010 Change 2011 2010 Change

Salaries and benets $9,246 $6,082 52% $24,125 $14,580 65%

Professional fees 1,117 753 48% 2,275 2,000 14%

Ofce and general 808 677 19% 2,606 1,879 39%

Travel and entertainment 667 420 59% 1,726 1,369 26%

Regulatory and transfer fees 93 95 -2% 721 425 70%

Total general and administrative

expenses $11,931 $8,027 49% $31,453 $20,253 55%

G&A expense increased over the same period last year

primarily due to higher overhead costs and higher stock

based compensation expenses. Salaries & Benets and

Ofce & General expense has increased due to increased

headcount. A signicant driver of the Salaries & Benet

increase is related to the amount required to be accrued for

Stock Appreciation Rights (SARs) increased to $12.2

million from $5.0 million year on year. SARs expense

is tied to the Companys share price, which has seen a

dramatic increase from C$6.06 to C$15.20 since December

31, 2010. The Company had 49 full-time employees; and

19 full time contractors as of December 31, 2011 (2010: 48

and 17, respectively).

Regulatory & Transfer fees are higher for the quarter

and full year due to the Companys costs incurred in the

required transition to IFRS standards as well as costs

related to the Companys graduation to the main board of

the Toronto Stock Exchange.

Exploration

3 Months ended

December 31,

Years ended

December 31,

2011 2010 Change 2011 2010 Change

Unsuccessful exploration costs $1,545 $62,786 -98% $8,374 $72,170 -88%


18/6416

Finance costs

3 Months ended

December 31,

Years ended

December 31,

2011 2010 Change 2011 2010 Change

Finance costs $1,549 $92 -% $4,825 $2,295 110%

After allowing for mark-to-market adjustments on the

cashless warrants liability, interest expense increased year

over year as the Company had higher debt balances. Total

gross debt (excluding interest) at December 31, 2011 was

$80 million versus $71.3 million at December 31, 2010.

The Companys average interest rate was 4.14% for the

year ended December 31, 2011 (2010: 4.09%). Interest

expense for 2010 includes interest on the Companys

amounts due to shareholder (which were repaid in Q310)

and long-term debt.

Depletion and Depreciation

3 Months ended

December 31,

Years ended

December 31,

2011 2010 Change 2011 2010 Change

Oil and gas depreciation & depletion $20,968 $13,689 53% $59,447 $30,911 92%

Effect of change in inventory 1,773 (2,093) -185% 1,338 (1,490) -190%Corporate depreciation 103 62 66% 351 237 48%

Depletion, depreciation, amortization andimpairment expense $22,844 $11,658 96% $61,136 $29,658 106%

$ per bbl $17.90 $26.88 $17.82 $10.79

Overall depreciation expense increased due to higher

production rates both on a quarterly and full year basis.

Depletion rates increased on a per barrel basis for the

full year due to an increase in the depletion rate at Bua

Ban Main associated with the reduction in reserves at

December 31, 2010. This was partially offset by the

commencement of production at Bua Ban North in Q311.

The signicant decline in the depletion rate from Q311 to

Q411 is due to the inclusion of a full quarter of production

at Bua Ban North using the depletion rate and reserves

number per the RPS report.

Gains on disposal of property,plant and equipment

3 Months ended

December 31,

Years ended

December 31,

2011 2010 Change 2011 2010 Change

Gains on disposal of property, plantand equipment $- $- - $873 $- -

In 2011, the Company disposed of the Ocean 66 drilling

platform, which was undergoing refurbishment. After

review, it was determined that the costs to complete the

project far outweighed comparable costs to purchase an

already refurbished unit. The sale of the unit resulted in a

one-time gain of $0.2 million after being entirely written

off earlier in 2011.

The remainder of the 2011 gain is attributable to the

termination of certain nance lease obligations on

production equipment in Q3 2011.

The full year 2011 charge relates to a write down of

costs associated with the fracture jobs on Benjarong, the

results of which did not lead to commercially acceptable

performance, and relinquishment of some acreage at G5/50.

As a result of the Companys transition to IFRS reporting,

it is now expensing dry hole costs on exploration prospects

which prove to be unsuccessful.


19/6417

Share of net income from Apico LLC

3 Months ended

December 31,

Years ended

December 31,

2011 2010 Change 2011 2010 Change

Coastals 36.1% of Apicos netincome $2,732 $(619) - $15,583 $9,041 72%

Amortization of Coastals excessbasis (169) (298) - (1,056) (1,109) -5%

Earnings from SignicantlyInuenced Investee, net of taxes $2,563 $(917) - $14,527 $7,932 83%

100% Field Production volumes(mmcf/d) 53.4 93.2 -43% 84.8 94.2 -10%

12.6% net to Coastal (mmcf/d) 6.7 11.7 -43% 10.7 11.8 -10%

Taxes

3 Months ended

December 31,

Years ended

December 31,

2011 2010 Change 2011 2010 Change

Current tax expense (recovery) $- $(7) - $135 $(7) -

Deferred income charge (credit) 20,201 (40,850) - 57,882 (11,768) -

Taxes $20,201 $(40,857) - $58,017 $(11,775) -

The Companys future income tax liability primarily relates

to Thai taxes. Under IFRS, these taxes are calculated in

Thai Baht (the payment currency) and then converted to

US dollars.

Under the equity method of accounting for investments,

the Company records its share of the net income of Apico

based on Apicos quarterly reported net income. Apicos

revenue declined in the fourth quarter due to decreased

industrial demand following the oods in Thailand in Q3/

Q4 2011. Demand has since increased in 2012.

The Q410 and full year 2010 results for Apico have been

adjusted to reect an approximate charge of $3MM for

dry hole costs in Q410. Apico uses US GAAP and the

full cost method for reporting purposes. As part of the

transition to IFRS, the Company had to make adjustments

to convert Apicos results to be IFRS compliant.

On September 25, 2006, the Company acquired an

additional interest in Apico for an amount greater than

its proportionate share of net assets of Apico (excess

basis). The excess basis was allocated to Apicos oil &

gas properties and is being amortized using the units of

production method beginning in Q1 2007.

In the rst quarter of 2012, the Company acquired an

additional 2.9% of Apico, bringing its total holdings to

39%. The effective date of the transaction is January 1,

2012, and thus future nancial statements will reect this

increased holding.

Net income

3 Months ended

December 31,

Years ended

December 31,

2011 2010 Change 2011 2010 Change

Net income and comprehensiveincome attributable to CoastalEnergy $18,892 $(61,561) - $47,359 ($12,390) -

Basic earnings per share $0.17 $(0.56) - $0.42 $(0.12) -

Diluted earnings per share $0.16 $(0.56) - $0.41 $(0.12) -


20/6418

2011 2010

Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1

Revenues and Other Income

Oil sales $128,929 $81,670 $64,628 $72,556 $33,246 $68,688 $42,164 $49,510

Royalties (11,955) (6,295) (5,018) (5,845) (2,769) (6,828) (3,154) (3,650)

Gain (loss) on derivative (8,838) 11,182 (871) (20,657) (18,181) - (1) (65)

Interest income 2 2 1 1 1 1 1 2

Other income (336) (467) (1,157) (428) (913) (296) 33 211

107,802 86,092 57,583 45,627 11,384 61,565 39,043 46,008

Expenses

Production 32,773 27,148 17,124 22,218 17,996 16,124 8,211 10,995Depreciation, Depletion,

Amortization andImpairment 22,844 13,308 11,698 13,286 22,364 8,343 3,684 5,973

General and Administrative 11,931 7,802 6,457 5,263 8,027 4,334 4,095 3,797

Exploration 1,545 345 931 5,553 62,786 26 91 9,267

Debt nancing fees 273 258 31 234 256 23 119 124

Finance expenses 1,549 913 1,201 1,162 92 722 749 732Gains on disposal of

property, plant andequipment - (873) - - - - - -

70,915 48,901 37,442 47,716 111,521 29,572 16,949 30,888

Taxes 20,201 22,628 12,005 3,183 (40,857) 9,872 12,669 6,541Share of net income (loss) from

Apico LLC 2,563 4,436 4,272 3,256 (917) 2,709 3,156 2,984

Net income (loss) beforenon-controlling interests 19,249 18,999 12,408 (2,016) (60,197) 24,830 12,581 11,563

Non Controlling interest (357) 14 (592) (346) (1,364) 247 (55) 5

Net income (loss) attributable

to Coastal Energy Company 18,892 19,013 11,816 (2,362) (61,561) 25,077 12,526 11,568

EBITDAX(a) $75,085 $44,658 $39,467 $42,479 $4,413 $44,508 $29,854 $35,496

Basic earnings (loss) $0.17 $0.17 $0.11 ($0.02) ($0.56) $0.23 $0.11 $0.11

Diluted earnings (loss) $0.16 $0.16 $0.10 ($0.02) ($0.56) $0.22 $0.11 $0.10

Note:(a)EBITDAX is a non-IFRS and non-Canadian GAAP measure and is dened as earnings before interest, nancing fees, taxes,

depreciation, amortization, exploration costs and other one-time items adjusted for non-cash items such as unrealized gains andlosses on risk management contracts, unrealized foreign exchange gains or losses and Share-Based Compensation (see reconciliationbelow.)

S U M M A R Y O F Q U A R T E R L Y R E S U L T S

Signicant factors inuencing Quarterly Results include

The volatility of global crude oil prices has a direct effect

on the Companys revenue as well as unrealized gains

or losses on risk management contracts. The Company

realized a higher sales price year over year, but a lower

sales price sequentially.

The Company has incurred higher lease operating

expenses in 2011 due to a full year of Bua Ban Main

operating expenses, the addition of production and

associated expenses at Bua Ban North B as well as

increased repair and maintenance expense related to storm

damage. The Company also had increased workover

expenses in 2011 related to replacing a number of

downhole pumps.

The Company has incurred higher general and

administrative expenses as the substantial increase in the

Companys stock price has increased its Share-Based

Compensation expense as well as the accrual value of

stock-linked cash compensation.


21/6419

The Company transacts business in multiple currencies;

therefore the volatility of global currency exchange rates

has a direct effect on the Companys foreign exchange

(gains) losses.

Cash Flow Analysis

The Companys cash and cash equivalents at December

31, 2011 were $23.0 million, an increase of $19.1 million

from $3.9 million at December 31, 2010. The Companys

primary source of funds came from operations, shares

issued for cash of $7.9 million from one-time option

exercises, and $6.3 million increase in borrowings. Cash

and cash equivalents were primarily used to fund property,

plant and equipment expenditures of $165.1 million and to

fund working capital.

Capital Expenditures

Capital expenditures (on an accruals basis) amounted

to $153.5 million in 2011, compared to $144.7 million in,

2010, respectively. The Q411 expenditures were almost

entirely related to exploration, appraisal and developmentdrilling at Bua Ban North. The following table sets forth a

summary of the Companys capital expenditures incurred:

Capital Expenditures

Years ended

December 31,

2011 2010

Seismic, geological andgeophysical studies $5,145 $4,885

Drilling and completions 113,337 91,223

Facilities 6,081 40,450

Lease and well equipment 27,839 7,912

Administrative assets 1,133 279Total Capital Expenditures $153,535 $144,749

Equity Capital

Share Capital

Authorized 250,000,000 common shares with par value of

$0.04 each;

As of the date of this report, the Company had

114,225,476 common shares outstanding.

Warrants

As of December 31, 2010, the Company had 540,000warrants outstanding exercisable at CAD $1.136 per

share. During 2011, 340,000 warrants were exercised

resulting in the issuance of 286,082 common shares of

the Company. As of December 31, 2011, the Company

had 200,000 warrants outstanding at a weighted average

exercise price of CAD$1.136 per share.

Subsequent to December 31, 2011, no warrants were

exercised resulting in the issuance of no common shares of

the Company.

Stock OptionsDuring the year ended December 31, 2011, the Company

granted 1,591,947 stock options with a weighted average

exercise price of $13.58. In addition, options exercised

and forfeited were 3,602,288 and 238,929 respectively. As

of December 31, 2011 the Company had 8,545,717 stock

options outstanding with a weighted average exercise

price of $5.79. Subsequent to December 31, 2011, 673,297

options were exercised and 3,732 options were forfeited.

GrantDate

NumberOutstanding

RemainingContractual Life

ExercisePrice

ExpiryDate

NumberExercisable

Jan. 25, 2008 230,270 1.00 year $3.87 (Cdn$3.94) Jan. 26, 2013 230,270

May 05, 2008 25,000 1.25 years $4.37 (Cdn$4.44) May 06, 2013 25,000

Jul. 14, 2008 54,166 1.50 years $3.55 (Cdn$3.61) Jul. 15, 2013 54,166

Sep. 16, 2008 100,000 1.75 years $2.23 (Cdn$2.27) Sep. 16, 2013 100,000

Sep. 23, 2008 898,000 2.00 years $3.87 (Cdn$3.94) Feb. 05, 2013 898,000

Jan. 02, 2009 1,306,595 2.00 years $1.33 (Cdn$1.35) Jan. 01, 2014 1,306,596

Dec. 01, 2009 2,241,544 3.00 years $5.04 (Cdn$5.13) Nov. 30, 2014 1,447,823

Dec. 28, 2010 1,471,166 4.00 years $5.53 (Cdn$5.75) Dec. 27, 2015 467,987

Dec 14, 2011 1,541,947 5.00 years $13.81 (Cdn$14.04) Dec 13, 2016 -

7,868,689 4,529,842

Restricted stock units

During the year ended December 31, 2011, the Company

granted 205,628 restricted stock units with a weighted

fair value of $12.93. The following table summarizes the

outstanding RSUs at December 31, 2011 and as of the

date of this report:


22/6420

GrantDate

NumberOutstanding

RemainingContractual Life

Grant DateFair Value

ExpiryDate

Dec. 14, 2011 205,628 3.00 years $12.93 Dec. 14, 2014

205,628

Off-Statement of Financial Position Arrangements

The Company has no off-statement of nancial position

arrangements.

Related Party Transaction

Effective September 25, 2006, the Company assumed

a note payable to O. S. Wyatt, Jr., the shareholder of

NuCoastal Thailand Limited (NuCoastal) for $4.6

million. The original note was unsecured, accrued interest

at 4% and was set to mature on July 20, 2007. The note

and its accrued interest were periodically renegotiated.

The note was fully repaid in Q3 2010.

Commitments and Contingencies

All the Companys commitments and contingencies

are described in Note 23 to the Consolidated FinancialStatements for the year ended December 31, 2011.

Subsequent Events

On February 22, 2012, the Company announced the

acquisition of an additional 2.9% stake in Apico LLC for

US $9.25 million in cash, bringing the Companys interest

in Apico LLC to 39%. This agreement was effective

January 1, 2012. Apico LLC holds a 35% interest in the

Sinphuhorm Gas Field, thus increasing the Companys net

interest in this eld to 13.65%.

Also during Q1 2012, the Company purchased the Sorayajack-up rig which had been used on the Songkhla A

eld. The purchase price for the jack-up rig was $20.25

million. In relation to this purchase, the Company has also

agreed to purchase the processing equipment currently

being used on the Soraya for approximately $4.5 million.

The purchase agreement on the processing equipment is

expected to close in Q3 2012.

During 2012 the Company has also announced the results

of the rst exploration well at Bua Ban South. The Bua

Ban South A-01 well encountered 88 feet of net pay in the

Lower Oligocene with 12 percent porosity. The Companyplans to drill future appraisal wells to determine the size of

this oil accumulation.

Critical Accounting Policies, Estimates and New

Accounting Pronouncements

A detailed summary of the Companys critical accounting

policies and estimates is included in Note 3 to theaudited nancial statements for the twelve months ended

December 31, 2011. Given the transition to International

Financial Reporting Standards we strongly advocate

readers of this document read and understand the policies

described in that document.

Risks and Uncertainties

Coastal has published its assessment of its business risks

in the Risk Factor section of its Annual Information Form

(AIF) dated March 28, 2012 (available on SEDAR at

www.sedar.com.) It is recommended that this document

be reviewed for a thorough discussion of risks faced by theCompany.

The Company is subject to a number of risk factors due to

the nature of the petroleum and gas business in which it

is engaged, not the least of which are adverse movements

in commodity prices, which are impossible to forecast.

The Company is also subject to the oil and gas services

sector which, from time to time, may have limited available

capacity and therefore may demand premium rates. The

Company seeks to counter these risks as far as possible by

selecting exploration areas on the basis of their recognized

geological potential to host economic returns.

Industry

The Company is engaged in the acquisition of petroleum

and natural gas properties, an inherently risky business,

and there is no assurance that an additional economic

petroleum and natural gas deposit will ever be discovered

and subsequently put into production. Most exploration

projects do not result in the discovery of commercially

viable petroleum and natural gas deposits. The geological

focus of the Company is on areas in which the geological

setting is well understood by management.


23/6421

Petroleum and Gas Prices

In recent years, the petroleum and natural gas exploration

industry has seen signicant growth, primarily as a result

of increased global demand, led by India and China.

During this period, prices for petroleum have steadily

increased, resulting in multi-year price highs. Prior to

this recent surge, large companies found it more feasible

to grow their reserves and resources by purchasing

companies or existing oilelds. However, with improvingprices and increasing demand, a discernible need for the

development of exploration projects has arisen. Junior

companies have become key participants in identifying

properties of merit to explore and develop.

The price of petroleum and natural gas is affected by

numerous factors beyond the control of the Company

including global consumption and demand for petroleum

and natural gas, international economic and political

trends, uctuations in the U.S. dollar and other currencies,

interest rates, and ination. Continued volatility in

commodity prices may adversely affect the Companysoperating cash ow.

Operating Hazards and Risks

Exploration for natural resources involves many risks,

which even a combination of experience, knowledge

and careful evaluation may not be able to overcome.

Operations in which the Company has a direct or indirect

interest will be subject to all the hazards and risk normally

incidental to exploration, development and production

of natural resources, any of which could result in work

stoppages, damages to persons or property and possible

environmental damage. Although the Company may

obtain liability insurance in an amount which is expected

to be adequate, the nature of these risks is such that

liabilities might exceed policy limits, the liabilities and

hazards might not be insurable, or the Company might

not elect to insure itself against such liabilities due to the

high premium costs or other reasons, in which event the

Company could incur signicant costs that could have a

material adverse effect upon its nancial condition.

Reserve Estimates

Despite the fact that the Company has reviewed theestimates related to potential reserve evaluation and

probabilities attached thereto and it is of the opinion that

the methods used to appraise its estimates are adequate,

these gures remain estimates, even though they have

been calculated or validated by independent appraisers.

The reserves disclosed by the Company should not

be interpreted as assurances of property life or of the

protability of current or future operations given that

there are numerous uncertainties inherent in the estimation

of economically recoverable oil and natural gas reserves.

Disruptions in Production

Other factors affecting the production and sale of oil and

natural gas that could result in decrease of protability

include: (i) expiration or termination of leases, permits or

licenses, or sales price re-determinations or suspension of

deliveries; (ii) future litigation; (iii) the timing and amount

of insurance recoveries; (iv) work stoppages or other labor

difculties; (v) worker vacation schedules and related

maintenance activities; and (vi) changes in the marketand general economic conditions. Weather conditions,

equipment replacement or repair, res, amounts of rock

and other natural materials and other geological conditions

can have a signicant impact on operating results.

Cash Flows and Additional Funding Requirements

The Company presently has revenue from its Gulf of

Thailand production and earnings from its interest in

Apico, which is accounted for under the equity method

on the consolidated statement of operations. In order to

further develop the Gulf of Thailand assets, substantial

capital will be required. The sources of capital presentlyavailable to the Company for development are cash ow

from production or the issuance of debt or equity. The

Company has sufcient nancial resources to undertake its

rm obligations for the next 12 months.

The Company is exposed to uctuations in short-term

interest rates on amounts drawn under its revolving credit

facilities. The Company has not hedged these rates given

the need to remain exible in borrowing and repaying the

outstanding balances.

EnvironmentalThe Companys exploration activities are subject to

extensive laws and regulations governing environmental

protection. Although the Company closely follows and

believes it is operating in compliance with all applicable

environmental regulations, there can be no assurance that

all future requirements will be achievable on reasonable

terms. Failure to comply may result in enforcement actions

causing operations to cease or be curtailed and may

include corrective measures requiring capital expenditures


24/6422

Laws and Regulations

The Companys exploration activities are subject to local

laws and regulations governing prospecting, drilling,

development, exports, taxes, labor standards, occupational

health and safety, and other matters. Such laws and

regulations are subject to change, can become more

stringent and compliance can therefore become more

costly.

The political unrest in Thailand has manifested itself in

recent protests and violence in Bangkok. This unrest

and its related violence have not affected our Thailand

production operations; but there can be no guarantee that

operations will not be affected in the future. As a safety

precaution for our Bangkok based employees, we have on

occasion shut down our Bangkok ofce and allowed those

employees to work from home. We have also reviewed

contingency plans for our third country nationals to ensure

their safe exit from Thailand should the need arise.

There are also many risks associated with operationsin international markets, including changes in foreign

governmental policies relating to crude oil and natural

gas taxation, other political, economic or diplomatic

developments, changing political conditions and

international monetary uctuations. These risks

include: political and economic instability or war; the

possibility that a foreign government may seize our

property with or without compensation; conscatory

taxation; legal proceedings and claims arising from our

foreign investments or operations; a foreign government

attempting to renegotiate or revoke existing contractual

arrangements, or failing to extend or renew such

arrangements; uctuating currency values and currency

controls; and constrained natural gas markets dependent

on demand in a single or limited geographical area.

The Company applies the expertise of its management,

its advisors, its employees and contractors to ensure

compliance with current local laws.

Title to Oil and Gas Properties

While the Company has undertaken customary due

diligence in the verication of title to its oil and gas

properties, this should not be construed as a guarantee oftitle. The properties may be subject to prior unregistered

Petroleum Agreements or transfers and title may be

affected by undetected defects.

Dependence on Management

The Company strongly depends on the business and

technical expertise of its senior management team

and there is little possibility that this dependence will

decrease in the near term. The loss of one or more of these

individuals could have a material adverse effect on the

Company.

Apico Financial Reporting

The Company accounts for its 36.1% investment in Apico

(to be 39% in 2012 following the acquisition of additional

interest) under the equity method whereby it records its

share of Apicos earnings as earnings from a signicantly

inuenced investee. Apico is required to provide the

partners its nancial statements under the Joint Venture

Agreement on a timely basis. While the Company has a

seat on the Board of Directors of Apico, it does not controlthe Board or the management of Apico. Therefore, the

Company relies heavily on Apico management to provide

timely and accurate nancial information to the partners.

Risk Management and Financial Instruments

Coastal provides a risk management and nancial

instruments discussion on its exposure to and management

of credit risk, liquidity risk and market risk in Note 28 to

the audited nancial statements as at and for the period

ended December 31, 2011 and 2010.

Managements Report on Internal Control overFinancial Reporting

As of June 30, 2011, the Companys common stock

was listed and traded on the TSX-Venture exchange.

Effective July 5, 2011, the Companys common stock was

listed and began trading on the Toronto Stock Exchange

and was simultaneously de-listed on the TSX-Venture

exchange. In compliance with Exemption Orders issued

in November 2007 and revised in December 2008 by

each of the securities commissions across Canada, the

Chief Executive Ofcer (CEO) and Chief Financial

Ofcer (CFO) of the Company led the VentureIssuer Basic Certicate with respect to the nancial

information contained in the unaudited condensed interim

nancial statements and the respective accompanying

Managements Discussion and Analysis for the rst three

(3) quarters of 2011.

In contrast to the certicate under National Instrument

(NI) 52-109 (Certication of Disclosure in Issuers

Annual and Interim Filings), the Venture Issuer Basic

Certication does not include representations relating to

the establishment and maintenance of disclosure controls

and procedures and internal control over nancial

reporting, as dened in NI 52-109.

Beginning with this nancial ling, the CEO and CFO

will be required to le their respective certicates under

NI 52-109, and as such, will certify the following.


25/6423

Disclosure Controls and Procedures:

The Companys management under the supervision of,

and with the participation of, the CEO and CFO of

Coastal Energy Company have designed and evaluated

the effectiveness and operation of its disclosure controls

and procedures, as dened under National Instrument

52 109 Certication of Disclosure in Issuers Annual

and Interim Filings (NI 52-109). Disclosure controls

and procedures are designed to provide reasonableassurance that information required to be disclosed

in reports led with Canadian securities regulatory

authorities is recorded, processed, summarized and

reported in a timely fashion. The disclosure controls

and procedures are designed to ensure that information

required to be disclosed by the Company in such reports

is then accumulated and communicated to management,

including the CEO and the CFO, as appropriate, to allow

timely decisions regarding required disclosure. Due to the

inherent limitations in all control systems, an evaluation

of the disclosure controls can only provide reasonable

assurance over the effectiveness of the controls. The

disclosure controls are not expected to prevent and detect

all misstatements due to error or fraud. Based on the

evaluation of disclosure controls and procedures, the CEO

and CFO have concluded that, subject to the inherent

limitations noted above, the Companys disclosure controls

and procedures are effective as of December 31, 2011.

Internal Controls over Financial Reporting

The Companys management, with the participation of

its CEO and CFO, are responsible for establishing and

maintaining adequate internal controls over nancial

reporting (ICFR). Under the supervision of the CFO,

the Companys ICFR is a process designed to provide

reasonable assurance regarding the reliability of nancial

reporting and the preparation of nancial statements for

external purposes in accordance with GAAP.

All internal control systems, no matter how well designed,

have inherent limitations. Therefore, even those systems

determined to be effective can provide only reasonable

assurance with respect to nancial statement preparation

and presentation. As at the end of the period covered by

this Managements Discussion and Analysis, management

evaluated the effectiveness of the Companys ICFR as

required by Canadian securities laws.

Based on that evaluation, the CEO and CFO have

concluded that, as of the end of the three month periodcovered by this Managements Discussion and Analysis,

the ICFR were designed to provide reasonable assurance

regarding the reliability of nancial reporting and the

preparation of nancial statements for external purposes in

accordance with GAAP.


26/6424

International Financial Reporting Standards Transition

Effective January 1, 2011, the Company began preparing

its nancial statements under International Financial

Reporting Standards (IFRS). As such, the accounting

policies of the Company have been adjusted to comply

with IFRS beginning with the statement of nancial

position as at January 1, 2010. A comprehensive summary

of all of the signicant changes, including reconciliations

of the Canadian GAAP nancial statements to thoseprepared under IFRS, is presented in Note 29 First Time

Adoption of IFRS of the Companys audited December

31, 2011 nancial statements.

Adopting IFRS did not impact the cash the Company

generated. However, the adoption of IFRS has had an

impact on the Companys statement of nancial position

and statement of income. Previously reported net income

for the fourth quarter of 2010 under IFRS is shown in the

following reconciliation:

Three Months endedDecember 31, 2010

$m

Year endedDecember 31,2010

$m

Net Income under Canadian GAAP (23.1) 4.9

Differences increasing (decreasing) reported net income:

Unsuccessful exploration costs (62.8) (72.2)

Income Taxes 27.2 27.7

Foreign exchange 0.9 3.5

Depletion (1.5) 26.8

Finance lease - (0.5)

Accretion 0.1 0.3

Property, Plant & Equipment - (1.1)

Share of joint ventures net income (3.6) (3.0)

Derivative liability - warrants 1.2 1.2

Total Differences in Net Income (38.5) (17.3)

Net Income under IFRS (61.6) (12.4)

Net income for the three and twelve months ended

December 31, 2011 was $18.9 million and $47.4

million, respectively under IFRS. The signicant IFRS

accounting adjustments to net income include the writeoff of costs associated with the frac jobs at Benjarong

(not commercially viable), and lower depletion due to the

way we were required to allocate our property base upon

transition to IFRS.

Outlook

Coastal anticipates further exploration drilling at the Bua

Ban South prospect in the rst half of 2012. The Company

then plans to return to Bua Ban North for furtherappraisal and development drilling. Following the receipt

of the requisite environmental permits, Coastal plans

further appraisal and development drilling at Songkhla.

The Company also has numerous prospects in its

inventory which will be drilled in coming quarters.


27/6425


28/6426

Management is responsible for the integrity and objectivity of the information contained in this report and for the

consistency between the consolidated nancial statements and other nancial and operating data contained elsewhere in

this report. The accompanying consolidated nancial statements have been prepared by management in accordance with

International Financial Reporting Standards using estimates and careful judgment, particularly in those circumstances

where transactions affecting a current period are dependent upon future events. The accompanying consolidatednancial statements have been prepared using policies and procedures established by management and fairly reect

the Companys nancial position, nancial performance and cash ows, within the International Financial Reporting

Standards framework. Management has established and maintains a system of internal controls that is designed to provide

reasonable assurance that assets are safeguarded from loss or unauthorized use and the nancial information is reliable

and accurate.

The Companys external auditors, Deloitte & Touche LLP, have audited the consolidated nancial statements. Their audit

provides an independent view as to managements discharge of its responsibilities insofar as they relate to the fairness of

reported nancial results and the nancial performance of the Company.

The Audit Committee of the Board of Directors have reviewed in detail the consolidated nancial statements with

management and have met with the external auditors. The Audit Committee has reported its ndings to the Board ofDirectors who have approved the consolidated nancial statements.

/s/ Randy Bartley /s/ William Phelps

President & Chief Executive Ofcer Chief Financial Ofcer

Houston, Texas USA

March 28, 2012

M A N A G E M E N T S R E P O R T


29/6427

To the Shareholders of Coastal Energy Company:

We have audited the accompanying consolidated nancial statements of Coastal Energy Company (the Company),

which comprise the consolidated statements of nancial position as at December 31, 2011, December 31, 2010 and

January 1, 2010, and the consolidated statements of operations and comprehensive income (loss), the consolidated

statement of changes in equity and consolidated statement of cash ow for the years ended December 31, 2011 andDecember 31, 2010, and the notes to the consolidated nancial statements.

Managements responsibility for the consolidated nancial statements

Management is responsible for the preparation and fair presentation of these consolidated nancial statements in

accordance with International Financial Reporting Standards, and for such internal control as management determines is

necessary to enable the preparation of consolidated nancial statements that are free from material misstatement, whether

due to fraud or error.

Auditors responsibility

Our responsibility is to express an opinion on these consolidated nancial statements based on our audits. We conducted

our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply

with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidatednancial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated

nancial statements. The procedures selected depend on the auditors judgment, including the assessment of the risks

of material misstatement of the consolidated nancial statements, whether due to fraud or error. In making those risk

assessments, the auditor considers internal control relevant to the entitys preparation and fair presentation of the

consolidated nancial statements in order to design audit procedures that are appropriate in the circumstances, but not for

the purpose of expressing an opinion on the effectiveness of the entitys internal control. An audit also includes evaluating

the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as

well as evaluating the overall presentation of the consolidated nancial statements.

We believe that the audit evidence we have obtained in our audits is sufcient and appropriate to provide a basis for ouraudit opinion.

Opinion

In our opinion, the consolidated nancial statements present fairly, in all material respects, the nancial position of Coastal

Energy Company as at December 31, 2011, December 31, 2010 and January 1, 2010, and its nancial performance and

its cash ow for the years ended December 31, 2011 and December 31, 2010 in accordance with International Financial

Reporting Standards.

March 28, 2012Chartered Accountants

I N D E P E N D E N T A U D I T O R S R E P O R T


30/6428

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSI VE INCOME ( LOSS)

US $000S

Years Ended December 31, 2011 2010

(Note 29)

Revenues and Other Income

Oil sales, net of royalties (Note 18) 318,670 177,207

Other income (Note 19) (21,566) (19,207)

297,104 158,000

Expenses

Production 99,263 53,326

Depreciation and depletion (Note 8) 61,136 29,658

Impairment (Note 8) - 10,706

General and administrative 31,453 20,253

Exploration (Note 7) 8,374 72,170

Debt nancing fees 796 522

Finance (Note 17) 4,825 2,295

Gains on disposal of property, plant and equipment (873) -

204,974 188,930

Net income (loss) before income taxes and share ofNet income from Apico LLC 92,130 (30,930)

Share of net income from Apico LLC (Note 9) 14,527 7,932

Net income (loss) before income taxes 106,657 (22,998)

Income taxes (Note 24)

Current 135 (7)

Deferred 57,882 (11,768)

58,017 (11,775)

Net income (loss) and comprehensive income (loss) 48,640 (11,223)

Net income (loss) and comprehensive income (loss) attributable to:

Shareholders of Coastal Energy 47,359 (12,390)

Non-controlling interest 1,281 1,167

48,640 (11,223)

Net income (loss) per share:

Basic (Note 22) 0.42 (0.12)

Diluted (Note 22) 0.41 (0.12)

The accompanying notes are an integral part of these consolidated nancial statements.


31/6429

C O N S O L I D A T E D S T A T E M E N T S O F F I N A N C I A L P O S I T I O N

US $000S

As at

December 31,

2011

December 31,

2010

January 1,

2010

$ $ $

(Note 29) (Note 29)

Assets

Current Assets

Cash 22,995 3,884 21,229Restricted cash (Note 4) 28,447 16,369 3,829

Accounts receivable (Note 5) 16,939 10,299 6,111

Derivative asset (Note 14) 59 135 66

Inventory (Note 6) 14,161 12,783 5,310

Prepaids and other current assets 1,094 606 526

Total current assets 83,695 44,076 37,071

Non-Current Assets

Exploration and evaluation assets (Note 7) 31,881 31,068 44,907

Property, plant and equipment (Note 8) 355,052 246,248 189,534

Investment in and advances to Apico LLC (Note 9) 47,698 47,261 55,225

Deposits and other assets 405 289 300Total non-current assets 435,036 324,866 289,966

Total Assets 518,731 368,942 327,037

Liabilities

Current Liabilities

Accounts payable and accrued liabilities (Note 10) 59,471 53,550 31,363

Deferred revenue (Note 11) - - 23,060

Current portion of long-term debt (Note 14) 55,662 36,262 10,266

Amounts due to shareholder (Note 13) - - 5,164

Obligations under nance leases (Note 16) - 885 35

Current portion of derivative liabilities (Note 14) 14,557 10,141 -

Derivative liability - Warrants (Note 12) 2,853 2,191 3,371

Total current liabilities 132,543 103,029 73,259

Non-Current Liabilities

Long-term debt (Note 14) 22,156 35,081 24,284

Obligations under nance leases (Note 16) - 579 1,439

Non-current portion of derivative liabilities (Note 14) 1,274 6,609 -

Deferred tax liabilities 69,767 11,885 23,653

Decommissioning liabilities (Note 15) 42,124 17,655 4,071

Total Non-Current Liabilities 135,321 71,809 53,447

Shareholders Equity (Note 22)

Common shares 211,554 201,303 198,121

Contributed surplus 16,401 15,971 13,932

Retained earnings (accumulated decit) 17,630 (29,729) (17,339)

Total Shareholders Equity 245,585 187,545 194,714

Non-controlling interest 5,282 6,559 5,617

Total equity 250,867 194,10

Documents

Coastal Annual 2011