New DirectioN s New Opportunities

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N e w D i r e c t i o N s N e w O p p o r t u n i t i e s

a n n u a l r e p o r t

2 01 2

The discipline to deliverDear Fellow shareholders:In 2012 coastal energy continued to build on the success of prior years. We made two discoveries—one offshore at Bua Ban south and one onshore at Dong Mun, contracted a second offshore drilling rig, expanded our prospect inventory and signed a contract to work outside thailand for the first time. these new directions and opportunities were among the highlights of our best year ever for production, revenue, eBItDaX and crude oil reserve growth.

t a b l e o f c o N t e N t s

1 President’s Report to the Shareholders

4 Financial and Operating Highlights

12 Management’s Discussion and Analysis

23 Management’s Report

26 Independent Auditor’s Report

27 Consolidated Statements of Operations and Comprehensive Income

28 Consolidated Statements of Financial Position

29 Consolidated Statements of Cash Flows

30 Consolidated Statement of Changes in Equity

31 Notes to the Consolidated Financial Statements

61 Corporate Information

1

Production for the year-end averaged 21,912 barrels of oil equivalent per day (BOEPD), a 90% increase over 2011. Revenue increased 115% in 2012 to $747 million, while EBITDAX (earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses) increased by 145%. Year-over-year certified 2P reserves grew by 40%. Once again, all of our exploration activities were funded with current cash flow.

Updated investment thesisWhile we no longer drill exclusively in Thailand, it remains our primary focus. Thailand provides a stable operating environ-ment and offshore properties with prospects for significant oil reserves. We have 1.4 million acres leased in the Gulf of Thailand and more than 30 prospects comprising 450 million barrels of oil (mmbl). Two other components of our core investment thesis are unchanged.

• Our offshore production and prospects are in shallow water, making for cost-effective development. In 2012 our overall cost-effec-tiveness improved further by acquiring— instead of leasing—the production facilities for our offshore operations.

• With approximately 30% of outstanding shares owned by management and the founding shareholder, we are motivated to succeed.

Doubling our drilling capabilitiesTo date, Coastal has relied on a single con-tracted drilling rig to support both exploration and development activities. In October we leased the Manta jackup drilling rig on a one-year contract. In December the Manta arrived at the Bua Ban North B field, where it has begun an eight-well development drilling campaign.

The addition of a second drilling rig is an important milestone for Coastal, as it enables us to conduct our development and explo-ration programs simultaneously. Given our active drilling program in 2013, we believe deploying two rigs is an appropriate step for unlocking the value of our prospect inventory.

Malaysian opportunity with PetroNasThe other reason a second rig is important is our expansion into Malaysia. In July we signed an eight-year Small Field Risk Service Contract with PETRONAS, the Malaysian-government-owned oil and gas company, to develop and produce petroleum from three offshore fields known as the KBM Cluster. The KBM Cluster fields have similar charac-teristics to our fields offshore Thailand.

Coastal will be the operator of the fields, and PETRONAS will remain the owner. We will provide the upfront development capital, undertaking the development drilling and production of the fields. We will recover 100% of our capital and operating expenditures and will be paid a service fee, which will be adjusted by key performance indicators based on the timely implementation of the field development plan and budget. Overall, we ex-pect the project will generate a rate of return approaching that of our Thailand assets, with very limited risk. Drilling of the first of 17 wells will begin in April, and first oil is expected in the second half of 2013.

2012 exploration and Production Our historical ratio of approximately 60% development drilling and 40% exploration drilling produced outstanding results for the year.

OffshoreOffshore development drilling continued in 2012, where we added 6.3 million barrels of oil (mmbl) of 1P reserves and 40.4 mmbl of 2P reserves. Offshore production for the full year was 19.738 barrels of oil per day (BOPD). In the Bua Ban South field, the most signifi-cant news was our first hydraulic fracturing program. Given its success, we expect it to unlock the millions of barrels of oil in lower porosity and permeability sands in the Songkhla basin.

OnshoreBased on information from new 3D seismic data for the area, we successfully completed the Dong Mun 3 sidetrack well. APICO, the

joint venture operating the property, subse-quently agreed to study commercializing the discovery. Coastal is APICO’s largest stake-holder, and we further increased our stake to 39% during the year. Production at Dong Mun 3 is expected to begin in 2015.

Production continued from the Sinphuhorm gas field, ending the year at approximately 2,000 BOEPD. This gas is under a 15-year sales agreement with the Nam Phong power plant.

what’s ahead in 2013 An entire year with the services of two drilling rigs ratchets up what we can accomplish in 2013. This includes the opportunity to de-risk 660 mmbl unrisked oil-in-place by year-end.

Our $315 million capital expenditure budget for the year is 13% lower than in 2012. The de-crease reflects completing the purchase and conversion of mobile operating production units (MOPUs) in 2012 and nearly completing a large 3D seismic data survey begun last year. Operating expenses are expected to average approximately $19.00 per bbl offshore Thailand, well below 2012 levels, reflecting the cost efficiencies achieved by purchasing our production facilities.

We are expecting higher-than-average capital expenditures onshore due to the beginning of pipeline construction and the development drilling at the Dong Mun field. By segment, the budget calls for $200 million in capital costs offshore Thailand, $40 million onshore Thailand and $75 million Malaysia.

The new directions and new opportunities introduced in 2012 point toward continued success in 2013. Your investment in Coastal helps make that success possible. I hope that the results we’ve delivered in our short history and the cost discipline we’ve exercised merit your continued confidence.

On behalf of the Board of Directors,

randy l. bartleyPresident and Chief Executive OfficerMarch 26, 2013

our five-year finding and development costs are an industry-leading $3.27 per barrel of oil equivalent (boe).

3

37,864

2009 2010 2011 2012

114,271

201,689

494,872

T O T A L A N N U A LE B I T D A XEBITDAX US$000s

0.55

2009 2010 2011 2012

0.87

1.63

3.27

O P E R A T I N G C A S H F L O WP E R S H A R ECash Flow Per Share US$000s

THAILAND

LAOS

CAMBODIA

MALAYSIA

BURMA

GULF OF

THAILAND

Block G5/50

Block G5/43 South

Songkhla •

Surat Thani •

Kuala Terengganu •

Bangkok •

SinphuhormField

13.7% W.I.

L 15/43

L 27/43

Dong MunField

39% W.I.

L 15/43 & L 27/4339% W.I.

APICO Operated

KBM Cluster70% W.I.

(Operator)

100% W.I.(Operator)

Coastal Energy’s 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 2012

5

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

3 Months ended December 31, Years ended December 31,

2012 2011%

Change 2012 2011%

ChangeFINANCIAL

Crude oil revenue $192,241 $128,929 49% $746,853 $347,783 115%

EBITDAX (1) $121,552 $75,085 62% $494,872 $201,689 145%Per share – Basic $1.07 $0.66 62% $4.36 $1.80 142%Per share – Diluted $1.04 $0.64 63% $4.24 $1.74 144%

Net Income $94,018 $18,892 398% $224,403 $47,359 374%Per share – Basic $0.83 $0.17 388% $1.98 $0.42 371%Per share – Diluted $0.80 $0.16 400% $1.92 $0.41 368%

Capital expenditures, excluding onshore $103,640 $44,614 132% $368,065 $153,535 140%

Total Assets $894,193 $518,731 72%

Working capital deficit ($70,350) ($45,995) 53%

Weighted average common shares outstandingBasic 113,160,080 112,998,419 -% 113,534,501 112,226,944 1%Diluted 117,175,857 117,849,003 -1% 116,701,941 115,994,340 1%

OPERATIONS

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

Crude oil revenue $105.74 $101.05 5% $105.83 $101.39 4%Royalties 11.12 9.37 19% 11.23 8.49 32%Production expenses 21.95 25.69 -15% 21.26 28.94 -27%Operating netback $72.67 $65.99 10% $73.34 $63.96 15%

Average daily crude oil production (bbls) (2) 18,954 13,386 42% 19,738 9,760 102%

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.

6

Fourth Quarter 2012 Highlights• Total Company production increased to 21,373 boe/d in

the fourth quarter of 2012 from 14,508 boe/d in the same period last year. Year over year offshore production was bolstered by the inclusion of a full quarter of production at the Bua Ban North A platform. Sequential quarterly offshore production was impacted downwardly in the fourth quarter due to a production facilities swap out at Bua Ban North as well as downtime at the Bua Ban North B platform while the second rig was mobilized to that location in December. Average onshore production for the fourth quarter of 2012 was 2,419 boe/d compared to 1,122 boe/d in 2011 as demand recovered following the severe flooding that occurred in Thailand during the second half of 2011. Total Company production for the full year 2012 increased to 21,912 boe/d from 11,540 boe/d in 2011 mainly due to the inclusion of a full year of production at Bua Ban North.

• EBITDAX for the full year of 2012 was $494.9 million, 145% higher than the $201.7 million recorded in 2011. Revenue and EBITDAX were driven higher by increased production and commodity prices. Crude oil inventory was 503,594 barrels at year end, the revenue from which will be recognized in 2013.

• The Company released the results of its third-party reserve evaluation report prepared by RPS Energy, Ltd. dated March 20, 2013 (effective date December 31, 2012). The Company reported significant gains in its 1P, 2P and 3P reserve bases, with volumetric increases of 9%, 40% and 78%, respectively. The Company’s 1P, 2P and 3P NAVs also increased significantly, rising by 21%, 43% and 62%, respectively.

• The second offshore drilling rig, the Atwood Manta, arrived on location at Bua Ban North in December 2012 and began a development drilling program at that location.

• The Company completed the acquisition of a 3D seismic survey over Blocks G5/43 and G5/50. The full interpreted data set is expected to be delivered in 2013, and the Company anticipates that new exploration prospects will be generated from this data set.

The following chart represents the Company’s Average BOE/D on an annual basis:

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

22,000

24,000

2008 2009 2010 2011 2012

Prod

uctio

n (B

OE

/ D

)

■ Onshore ■ Songkhla ■ Bua Ban Main ■ Bua Ban North

A N N U A L P R O D U C T I O N(boe/d)

2,174

4,010

1,127

14,601

1,828

5,534

2,017

6,345

1,308

1,780

5,336

1,466

2,958

1,785

470

Note: Bua Ban North came onstream in August 2011.

The following chart represents the Company’s growing cash operating netbacks ($/bbl) for its offshore production since first oil. Operating netback is based on sales volume and is a non-IFRS measure. See “Non-IFRS Measure” section within the MD&A.

$20.00

0

$40.00

$60.00

$80.00

$100.00

$120.00

Pre-

Tax

O�s

hore

Net

back

s ($

/ b

bl)

■ Cash Operating Netback ■ Production Expense ■ Royalties

O P E R A T I N G N E T B A C K S($/bbl))

$15.97$29.42

$45.09

$63.96$73.34

$11.16

$20.96

$19.41

$28.94$21.26

$1.50

$3.68

$5.97

$8.49$11.23

2008 2009 2010 2011 2012

7

EBITDAX Computation 2012 2011

Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1Net income (loss) attributable

to shareholders $94,018 $40,100 $42,150 $48,135 $18,892 $19,013 $11,816 $(2,362)

Add Back:Unrealized (gain) loss on

derivative (2,507) 362 (15,892) 4,007 3,663 (15,019) (7,744) 18,257Realized loss on derivative (a) 1,749 3,640 5,958 5,152 5,175 3,837 8,615 2,400Interest income (34) (2) (1) (2) (2) (2) (1) (1)Equity-based compensation 1,453 1,414 1,414 1,414 677 587 607 618Unrealized foreign exchange

(gain) loss (837) 18 (157) 91 268 (337) 308 149Finance expenses 1,574 1,940 195 1,006 1,549 913 1,201 1,162Debt financing fees 1,032 501 351 281 273 258 31 234Gain on sale of assets - (252) - - - (873) - -Depletion, depreciation and

accretion 16,727 14,778 18,590 20,044 22,844 13,308 11,698 13,286Taxation 8,377 44,913 77,384 48,311 20,201 22,628 12,005 3,183Exploration - 7,191 286 - 1,545 345 931 5,553

EBITDAX $121,552 $114,603 $130,278 $128,439 $75,085 $44,658 $39,467 $42,479

Note (a) 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 financing cost. This lead to a revision of the Q1 2011 EBITDAX number. EBITDAX is a non-IFRS measure.

The following chart represents the Company’s EBITDAX on an annual basis in USD$000s:

37,864 114,271

201,689

494,872

0

100,000

200,000

300,000

400,000

500,000

600,000

E B

I T D

A X

- (U

SD 0

00s)

E B I T D A X(US$ 000s)

2009 2010 2011 2012

8

a S S e t o v e r v I e w

Gulf of Thailand Properties

THAILAND

LAOS

CAMBODIA

MALAYSIA

BURMA

GULF OF

THAILAND

Block G5/50

Block G5/43 South

Songkhla •

Surat Thani •


Bangkok •

SinphuhormField

13.7% W.I.

L 15/43

L 27/43

Dong MunField

39% W.I.

L 15/43 & L 27/4339% W.I.

APICO Operated

KBM Cluster70% W.I.

(Operator)

100% W.I.(Operator)

Block G5/43 – Songkhla BasinThe Company holds a 100% working interest in Blocks G5/43 and G5/50 in the Gulf of Thailand. The current combined area of the blocks is approximately 2,777 square kilometres and average water depths are approximately 70 feet. Block G5/50 is an exploration concession north of the Songkhla basin and contains approximately 283 square kilometers of acreage within the boundaries of Block G5/43. As of December 31, 2012, the Company’s offshore assets have proven and probably (“2P”) reserves of approximately 120.4 million barrels of oil.

Bua Ban North FieldThe Bua Ban North field 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 significant 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 been developing the field over the past two years with both vertical and horizontal development wells. 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 2013. Production from Bua Ban North began in August 2011 and averaged 14,601 bbl/d during 2012. As of December 31, 2012, Bua Ban North had proven and probable (“2P”) reserves of approximately 95.2 million barrels of oil.

Bua Ban Main & South FieldsProduction from the Bua Ban Main field commenced in July 2010. The Bua Ban South field was discovered in 2012 and production has commenced in the first quarter of 2013. Bua Ban South began producing late Q1 2013 from the Miocene interval and from two wells drilled into the Oligocene and Eocene intervals which have been stimulated with hydraulic fracturing technology. The Company plans to continue developing the large Oligocene and Eocene resources at Bua Ban Main and South with hydraulic fracturing technology. Production from Bua Ban Main averaged approximately 1,127 bbl/d in 2012. As of December 31, 2012, Bua Ban Main & South had proven and probable (“2P”) oil reserves of 10.3 million barrels of oil.

Songkhla FieldThe Songkhla A field was the first field developed by the Company beginning in 2008. Production from Songkhla A averaged 4,010 bbl/d during 2012. As of December 31, 2012, Songkhla A had proven and probable (“2P”) reserves of approximately 14.1 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 file for another production license to encompass this field. As of December 31, 2012, Songkhla H had proven and probable (“2P”) reserves of approximately 0.9 million barrels of oil.

bua ban Northbua ban Main

bua ban southsongkhla hsongkhla a

9

G5/50The G5/50 concession is an exploration concession covering two basins north of the Songkhla basin. The Company has 3D seismic coverage of the basins and plans to drill its first exploration well on the concession in 2013.

Thailand Onshore

THAILAND

LAOS

CAMBODIA

MALAYSIA

BURMA

GULF OF

THAILAND

Block G5/50

Block G5/43 South

Songkhla •

Surat Thani •


Bangkok •

SinphuhormField

13.7% W.I.

L 15/43

L 27/43

Dong MunField

39% W.I.

L 15/43 & L 27/4339% W.I.

APICO Operated

KBM Cluster70% W.I.

(Operator)

100% W.I.(Operator)

The Company’s Thailand onshore interests are held through its equity investment in Apico. Apico has ownership interest in two production licenses and two petroleum concessions located in the Khorat Plateau in northeastern Thailand.

SinphuhormCoastal holds a net working interest of 13.7% in Blocks EU-1 and E-5N onshore Thailand through its 39.0% 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 field. Production at Sinphuhorm commenced on November 30, 2006, to supply the Nam Phong power plant with natural gas under a 15 year Gas Sales Agreement with PTT Public Company Limited. As of December 31, 2012, Sinphuhorm had 2P reserves of 23.8 million barrels of oil equivalent net to Coastal, and production averaged 2,174 boepd net to Coastal during 2012.

Coastal also holds a net 39.0% working interest in Block L27/43 (operated by Apico), which is located southeast of Sinphuhorm. 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 well flowed 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 have received commercial approval of the field and are currently evaluating development plans. The Dong Mun prospect contained 10.0 mmboe (net to Coastal) of contingent resources as of December 31, 2012.

Company has a net 39.0% working interest in Block L15/43 (operated by Apico), which surrounds the Sinphuhorm gas field.

Malaysia Offshore

THAILAND

LAOS

CAMBODIA

MALAYSIA

BURMA

GULF OF

THAILAND

Block G5/50

Block G5/43 South

Songkhla •

Surat Thani •


Bangkok •

SinphuhormField

13.7% W.I.

L 15/43

L 27/43

Dong MunField

39% W.I.

L 15/43 & L 27/4339% W.I.

APICO Operated

KBM Cluster70% W.I.

(Operator)

100% W.I.(Operator)

In June 2012 the Company entered into a contract with Petronas to develop the Kapal, Benang & Meranti cluster of fields offshore Malaysia. The Company will be reimbursed for all capital and operating expenditures associated with the KBM cluster. Additionally, it will earn a service fee which is adjusted according to its performance versus the agreed upon budget. The Company farmed out 30% of the contract to a local Malaysian oilfield service company in 2012. First oil from the project is expected in mid-2013.

Kapal

banangMeranti

10

o p e r a t I o n a l r e v I e w

Oil and Gas ReservesThe Company’s 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 Company’s 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 PropertiesThe Company’s Gulf of Thailand reserves were evaluated by RPS Energy, Ltd. (“RPS”). Selected data from their report follows. Their report, dated March 26, 2013, 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, reflecting the approximate relative energy content. The following reserve figures, before royalties for 2012 and 2011 reflect Coastal Energy’s 100% interest in its Gulf of Thailand concessions (Block G5/43 and G5/50.)

Gulf of ThailandOil and Gas Reserves (Gross)

December 31, 2012 December 31, 2011

oil (Mbbls)

gas (MMcf)

boe (Mbbls) Oil (Mbbls)

Gas (MMcf)

BOE (Mbbls)

Proved Reserves Developed producing 30,805 30,805 25,115 - 25,115Developed non-producing 2,736 2,736 17,638 - 17,638Undeveloped 35,261 35,261 19,736 - 19,736

total Proved 68,802 68,802 62,489 - 62,489

total Probable 51,592 51,592 17,453 - 17,453

total Proved Plus Probable 120,394 120,394 79,942 - 79,942

The forecasted prices used by RPS Group Ltd. in their evaluation for December 31, 2012, and December 31, 2011, were taken from RPS’s own internal estimates of future commodity prices. Forecasted prices as at December 31, 2012, and December 31, 2011, are as follows:

YearDecember 31, 2012

($/bbl)December 31, 2011

($/bbl)2012 n/a 105.802013 108.00 101.302014 102.00 96.802015 98.00 96.612016 95.00 98.632017 97.00 100.692018 99.00 102.792019 101.00 104.932020 103.00 107.112021 105.00 n/athereafter 2.0% 2.1%

The following table summarizes the present value of future net revenues discounted at 10% before income taxes at December 31, 2012 and 2011.

US $ millions based on forecasted prices at December 31, 2012 2011Proved Reserves:

Developed producing $1,521.9 $1,182.3Developed non-producing 135.2 852.1

Undeveloped 1,742.1 874.5

total Proved – gulf of thailand $3,399.2 $2,908.9

total Probable – gulf of thailand $1,238.7 $506.5

total Proved Plus Probable – gulf of thailand $4,637.9 $3,415.4

Thailand OnshoreRPS also evaluated the onshore reserves held via Apico effective December 31, 2012, and December 31, 2011. Selected data from RPS’s report follows.

11

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, reflecting the approximate relative energy content. The

following reserve figures, before royalties for 2012 and 2011 reflect Coastal Energy’s 36.1% interest in APICO as if the Company directly owned the onshore properties.

Thailand OnshoreOil and Gas Reserves (Gross)


oil (Mbbls)

gas (MMcf)

boe (Mbbls)

Oil (Mbbls)

Gas (MMcf)

BOE (Mbbls)

total Proved 144 42,873 7,290 222.4 46,680 8,025

total Probable 382 97,365 16,609 461.0 92,488 15,900

total Proved Plus Probable 526 140,238 23,899 683.4 139,168 23,925

The forecasted prices used by RPS Group Ltd. in their evaluations for December 31, 2012, and December 31, 2011, were taken from RPS’s own internal estimates of future commodity prices. Forecasted prices as at December 31, 2012, and December 31, 2011, are as follows:

Year

as at December 31, 2012 As at December 31, 2011condensate

($/bbl)condensate

($/bbl)Condensate

($/bbl)Condensate

($/Mcf)2012 n/a n/a 102.68 6.692013 97.40 8.40 98.44 6.752014 92.30 8.00 94.19 6.932015 88.60 7.70 94.03 7.052016 85.50 7.30 95.92 7.172017 87.90 7.50 97.86 7.152018 89.70 7.60 99.84 7.282019 91.40 7.80 101.85 7.402020 93.30 7.50 103.91 7.532021 95.10 7.70 n/a n/athereafter 2.0% 2.0% 2.0% 2.0%

The following table summarizes the present value of future net revenues discounted at 10% before income taxes at December 31, 2012 and 2011.

US $ millions based on forecasted prices at December 31, 2012 2011

total Proved –thailand onshore $174.5 $184.2

total Probable –thailand onshore $179.1 $158.6

total Proved Plus Probable –thailand onshore $353.6 $342.8

Oil and Gas Properties

Summary of Oil & Gas Properties Thailand Onshore Gulf of Thailand Totalsbalance, December 31, 2010 $47,261 $276,645 $323,906Additions during the period, net of disposals:

Exploration & development 1,446 176,655 178,101Equity earnings in Apico, net of distributions 47 - 47Depletion - (59,447) (59,447)Exploration expense - (8,374) (8,374)Amortization of excess basis in Apico (1,056) - (1,056)

balance, December 31, 2011 $47,698 $385,479 $433,177Additions during the period, net of disposals:

Increase in ownership of Apico LLC 9,250 - 9,250Exploration & development - 348,990 348,990Equity earnings in Apico, net of distributions 3,967 - 3,967Depletion - (71,539) (71,539)Exploration expense - (7,477) (7,477)Amortization of excess basis in Apico (649) - (649)

balance, December 31, 2012 $60,266 $655,453 $715,719

12

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

The following is Management’s Discussion and Analysis (“MD&A”) of the results and financial condition of Coastal Energy Company (“Coastal” or the “Company”). This MD&A, dated March 26, 2013, should be read in conjunction with the accompanying unaudited consolidated financial statements as at and for the three and twelve months ended December 31, 2012, and related notes thereto. Additional information related to the Company is available on SEDAR at www.sedar.com.

OverviewThe Company was incorporated under the Companies Law of the Cayman Islands on May 26, 2004. The Company is engaged in the exploration and development of oil and natural gas properties in Southeast Asia. The functional and reporting currency of the Company and its subsidiaries is the US dollar. The Company’s trading symbols are “CEN” on the TSX and “CEO” on the AIM exchange.

The Company’s 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, 2012:

Petroleum Concession

Coastal’s Working Interest

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

of Block G5/43) 100.0%Onshore Thailand (via Coastal’s 36.1%

ownership of Apico LLC (“Apico”))Blocks EU-1 and E-5N containing

the Sinphuhorm gas field 13.6%Block L15/43 (surrounding the

Sinphuhorm gas field) 39.0%Block L27/43 containing the Dong Mun

gas field 39.0%

The Company’s ownership interests in a risk service contract awarded by Petronas, the national oil company of Malaysia, as of December 31, 2012, is as follows:

Malaysia Risk Service Contract

Coastal’s Working Interest

Kapal, Benang, Meranti RSC 70%

Non-IFRS and Non-GAAP Measures This report contains financial terms that are not considered measures under International Financial Reporting Standard principles (“IFRS”), such as funds flow from operations, funds flow 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. Specifically, funds flow from operations and funds flow per share reflect cash generated from operating activities before changes in non-cash working capital. Management considers funds flow from operations and funds flow per share important as they help evaluate performance and demonstrate the Company’s ability to generate sufficient cash to fund future growth opportunities and repay debt. EBITDA is defined as earnings before interest, taxes, depreciation, amortization and earnings from significantly influenced 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 Company’s financial leverage. Profitability relative to commodity prices per unit of production is demonstrated by an operating netback. Working capital represents current assets less current liabilities.

Funds flow from operations, funds flow per share, EBITDA, EBITDAX, net debt, operating netbacks and working capital are not defined by IFRS, and consequently are referred to as non-IFRS 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 flow from operations, net income or other measures of financial performance calculated in accordance with IFRS.

13

Forward Looking StatementsCertain 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.

Financial ReviewThe following tables are analyses of the line items in the Company’s 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.

Average Daily Production (boe/d)

3 Months ended December 31,

Years ended December 31,

2012 2011 Change 2012 2011 ChangeSongkhla 3,821 5,247 -27% 4,010 5,336 -25%Bua Ban Main 1,042 1,234 -16% 1,127 1,466 -23%Bua Ban North 14,091 6,905 104% 14,601 2,958 394%Total Offshore Production 18,954 13,386 42% 19,738 9,760 102%Sinphuhorm (via Apico) 2,419 1,122 116% 2,174 1,780 22%Total Company 21,373 14,508 47% 21,912 11,540 90%

Offshore production for the full year 2012 increased significantly due to the inclusion of a full year of production from the Bua Ban North field. Fourth quarter offshore production increased significantly from the prior year period due to the inclusion of a full quarter of production at the Bua Ban North A platform, which was brought online beginning late in the fourth quarter 2011 and throughout the first quarter of 2012. Fourth quarter production at Bua Ban North was impacted downwardly versus the third quarter due to a production facilities swap out and downtime associated with initial operations of the second drilling rig to the Bua Ban North B platform. The Company expects to see continued gains in production following the 2013 development drilling program at Bua Ban North as well as the addition of production at Bua Ban South and Songkhla H.

The Company is planning to drill additional development wells at Bua Ban North in 2013, including several horizontal development wells as well as injection wells to maintain aquifer support. During 2013, the Company also plans to complete the wells previously drilled at Bua Ban South and drill additional development and appraisal wells there. The Company also plans to bring the Songkhla H discovery online in Q3 2013.

Onshore production rose significantly year over year for both the fourth quarter and the full year as natural gas demand in Thailand recovered from the severe flooding which impacted it in the third and fourth quarters of 2011.

The following table reconciles the Company’s offshore inventory, production and liftings.

Crude Oil Inventory (bbls)



2012 2011 Change 2012 2011 ChangeInventory Beginning of Period 577,863 380,754 52% 336,334 203,983 65%

+ Production 1,743,797 1,231,488 42% 7,224,115 3,562,408 103%- Sales / Liftings (1,818,066) (1,275,908) 42% (7,056,855) (3,430,057) 106%

Inventory, End of Period 503,594 336,334 50% 503,594 336,334 50%

The Company’s crude oil production is stored in floating storage and offloading vessels (“FSOs”) moored at the production platforms. The inventory represents crude oil produced and loaded onto the FSOs, but which has not yet been off-loaded for sale at the end of the period. The Company ended the year with 503,594 bbl in inventory, the revenue and associated expenses of which will be recognized in 2013.

14

Oil Sales, Average Benchmark and Realized Prices ($/bbl)



2012 2011 Change 2012 2011 ChangeOil Sales $192,241 $128,929 49% $746,853 $347,783 115%Dubai (Benchmark - $/bbl) $107.53 $106.50 1% $109.05 $106.31 3%Sales Price per bbl Sold ($/bbl) $105.74 $101.05 5% $105.83 $101.39 4%Sales Price as a Percentage of Dubai 98% 95% 97% 95%

Revenue increased dramatically for the three and twelve month periods ending December 31, 2012, over the same periods in the previous year. The increase was driven by significantly higher production and lifting volumes as well as a 5% increase in realized commodity pricing. The Company had 503,594 bbls of crude oil inventory at quarter end, the revenue from which will be recognized in 2013.

The sales price for the Company’s offshore oil is based on the Dubai benchmark price. The Company is receiving a higher percentage of its benchmark crude price as commodity prices have increased as the Company sells oil at a fixed discount to the benchmark price. In the fourth quarter of 2011, the Company signed a 2-year agreement to sell its crude oil at a fixed $1.75 per bbl discount to Dubai pricing. This price includes transportation costs.

Royalties



2012 2011 Change 2012 2011 ChangeRoyalties $20,218 $11,955 69% $79,280 $29,113 172%$ per bbl $11.12 $9.37 19% $11.23 $8.49 32%Royalties as a percent of revenue 11% 9.3% 11% 8.4%

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

volumes. Fourth quarter royalty rates increased both on a percentage basis and on a per barrel basis due to both higher lifting volumes and commodity prices.

Malaysia risk service contract



2012 2011 Change 2012 2011 ChangeReimbursement of expenses $4,099 $- - $4,099 $- -Expenses (4,099) - - (4,099) - -Net expense associated with Malaysia risk

service contract $- $- - $- $- -

During 2012, the Company entered into a Small Field Risk Service Contract (“RSC”) with Petronas to develop three oil fields offshore Malaysia. The Company began

incurring expenses associated with the initiation of Malaysian operations and pre-drilling expenditures in the fourth quarter of 2012.

Other income



2012 2011 Change 2012 2011 ChangeUnrealized gain (loss) on derivative

contracts $2,507 $(3,663) - $14,030 843 -Realized loss on derivative contracts (1,749) (5,175) - (16,499) (20,027) -Interest income 34 2 - 39 6 -Foreign exchange loss (47) (336) (2,340) (2,388) -Other income ($745) ($9,172) - ($4,770) ($21,566) -

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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 Company’s 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 Company’s mark to market gains and losses. The Company realized losses of $1.7 million in the fourth quarter, which was a decrease from prior quarters, as the last of the Company’s fixed price swap agreements entered into in 2010 expired in the fourth quarter. As of December 31, 2012, the Company’s hedge portfolio consists solely of zero cost collars covering approximately 1.55 mmbbl in aggregate through April 2014 with an average floor of $70.00 / bbl and an average ceiling of $125.19 / bbl. The reference instrument is ICE Brent crude oil.

The net derivative liability at December 31, 2012, may never be realized, depending upon commodity price movements between December 31, 2011 and expiry of the final contract (April 2014).

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 Company carrying out transactions and maintaining certain financial 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, 2012, are unrealised losses on cash retranslation of $2.5 million and $1.8 million, respectively (2011: $1.3 million and $1.8 million, respectively).

Production



2012 2011 Change 2012 2011 Change

Production expenses $40,418 $31,445 29% $152,238 $101,034 51%Effect of change in inventory (511) 1,328 -138% (2,239) (1,771) 26%

$39,907 $32,773 22% $149,999 $99,263 51%$ per bbl $21.95 $25.69 $21.26 $28.94

The year over year increase in fourth quarter production expenses was primarily driven by inclusion of a full quarter of operating expenses for a second production platform at Bua Ban North and, to a lesser extent, general oilfield price inflation. Fourth quarter operating costs declined significantly on a per barrel basis due to the production gains from Bua Ban North as well as the purchase of previously leased production facilites. Coastal expects per barrel costs to continue declining in coming quarters due to further production gains from Bua Ban

North over a relatively fixed lease operating cost base.

Workover expense was relatively unchanged year over year (2012: $12.1 million; 2011: $10.9 million) as was repair & maintenance expense (2012: $2.7 million; 2011: $2.9 million). The Company saw a significant decline in operating costs on a per barrel basis, due primarily to the purchase of previously leased production facilities throughout the year as well as higher production levels being spread over a relatively fixed operating cost base. Coastal expects this trend to continue in coming quarters.

General and Administrative Expenses



2012 2011 Change 2012 2011 ChangeSalaries and benefits $12,682 $9,246 37% $29,677 $24,125 23%Professional fees 883 1,117 -21% 4,481 2,275 97%Office and general 863 808 7% 2,863 2,606 10%Travel and entertainment 564 667 -15% 2,093 1,726 21%Regulatory and transfer fees 195 93 110% 582 721 -19%Total general and administrative

expenses $15,187 $11,931 27% $39,696 $31,453 26%

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G&A expense increased over the same period last year primarily due to higher overhead costs and higher stock based compensation expenses. Salaries & Benefits and Office & General expense has increased due to increased headcount. A significant driver of the Salaries & Benefit increase is related to the amount required to be accrued for Stock Appreciation Rights (“SARs”) which increased to $12.2 million from $5.0 million year on year. SARs expense is tied to the Company’s share price, which has seen a dramatic increase from C$15.20 at December 31,

2011, to C$19.96 at December 31, 2012. The Company had 76 full-time employees and 32 full-time contractors as of December 31, 2012 (2011: 49 and 19, respectively).

Regulatory & Transfer fees are higher for the three months ended Q4 2012 relative to Q4 2011 as a result of increase in the cost of compliance activities. The decrease in Regulatory & Transfer fees year on year is largely due to the level of expenditures incurred in 2011 following the graduation of the Company to the main board of the Toronto Stock Exchange.

Exploration



2012 2011 Change 2012 2011 ChangeUnsuccessful exploration costs $- $1,545 - $7,477 $8,374 -11%

As a result of the Company’s transition to IFRS reporting, it is now expensing dry hole costs on exploration prospects which prove to be unsuccessful.

The 2012 charge relates to the writing off of dry hole costs at the Company’s Songkhla J prospect.

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.

Finance costs



2012 2011 Change 2012 2011 ChangeFinance costs $1,574 $1,549 2% $4,715 $4,825 -2%

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, 2012, was

$100.0 million versus $80.0 million at December 31, 2011. The Company’s average interest rate was 5.73% for the year ended December 31, 2012 (2011: 5.14%).

Depletion and Depreciation



2012 2011 Change 2012 2011 ChangeOil and gas depreciation & depletion $18,713 $20,968 -11% $71,539 $59,447 20%Effect of change in inventory (2,138) 1,773 -221% (2,068) 1,338 -255%Corporate depreciation 152 103 48% 668 351 90%Depletion, depreciation, amortization and impairment expense $16,727 $22,844 -27% $70,139 $61,136 15%$ per bbl $9.20 $17.90 $9.94 $17.82

Overall depreciation expense increased due to higher production rates both on a quarterly and full year basis. Depletion rates declined significantly on a per barrel

basis both on a quarterly and full year basis due to the substantial increase in the Company’s reserves as a result of the inclusion of Bua Ban North.

Gains on disposal of property, plant and equipment



2012 2011 Change 2012 2011 ChangeGains on disposal of property, plant and

equipment $- $- - $252 $873 -

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The gain in 2012 largely relates to disposal of surplus equipment acquired as part of the purchase of the Richmond rig.

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 finance lease obligations on production equipment in Q3 2011.

Taxes



2012 2011 Change 2012 2011 ChangeCurrent tax expense $26,297 $- - $150,329 $135 -Deferred income charge (credit) (17,920) 20,201 - 28,656 57,882 -Taxes $8,377 $20,201 - $178,985 $58,017 -

The Company’s 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.

Share of net income from Apico LLC



2012 2011 Change 2012 2011 ChangeCoastal’s 39.0% (2011: 36.1%) of Apico’s

net income $5,251 $2,732 92% $19,759 $15,583 27%Amortization of Coastal’s excess basis (182) (169) 8% (649) (1,056) -39%Earnings from Significantly Influenced

Investee, net of taxes $5,069 $2,563 98% $19,110 $14,527 32%100% Field Production volumes

(mmcf/d) 103.4 53.4 94% 92.3 84.8 9%13.7% (2011: 12.6%) net to Coastal

(mmcf/d) 14.1 6.7 110% 12.7 10.7 19%

Under the equity method of accounting for investments, the Company records its share of the net income of Apico based on Apico’s quarterly reported net income. Apico’s revenue increased in the fourth quarter and for the full year due to recovery of natural gas demand in Thailand following the floods in Thailand in Q3/Q4 2011.

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 Apico’s 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 Apico’s oil & gas properties and is being amortized using the units of production method beginning in Q1 2007.

In the first 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.

Net income



2012 2011 Change 2012 2011 ChangeNet income and comprehensive income

attributable to Coastal Energy $94,018 $18,892 398% $224,403 $47,359 374%Basic earnings per share $0.83 $0.17 388% $1.98 $0.42 371%Diluted earnings per share $0.80 $0.16 400% $1.92 $0.41 368%

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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

2012 2011Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1

Revenues and Other IncomeOil sales $192,241 $170,894 $194,639 $189,079 $128,929 $81,670 $64,628 $72,556 Royalties (20,218) (18,305) (20,514) (20,243) (11,955) (6,295) (5,018) (5,845)Reimbursement of expenses

under Malaysia risk service contract 4,099 - - - - - - -

Gain (loss) on derivative 758 (4,002) 9,934 (9,159) (8,838) 11,182 (871) (20,657)Interest income 34 2 1 2 2 2 1 1 Other income (47) (1,122) (157) (1,014) (336) (467) (1,157) (428)

176,867 147,467 183,903 158,665 107,802 86,092 57,583 45,627 Expenses

Production 39,907 32,718 41,164 36,210 32,773 27,148 17,124 22,218 Malaysia risk service

contract 4,099 - - - - - - - Depreciation, Depletion,

Amortization and Impairment 16,727 14,778 18,590 20,044 22,844 13,308 11,698 13,286

Net profits interest 133 39 869 - - - - - General and Administrative 15,187 9,125 7,057 8,327 11,931 7,802 6,457 5,263 Exploration - 7,191 286 - 1,545 345 931 5,553 Debt financing fees 1,032 501 351 281 273 258 31 234 Finance expenses 1,574 1,940 195 1,006 1,549 913 1,201 1,162 Gains on disposal of

property, plant and equipment - (252) - - - (873) - -

78,659 66,040 68,512 65,868 70,915 48,901 37,442 47,716 Taxes 8,377 44,913 77,384 48,311 20,201 22,628 12,005 3,183 Share of net income (loss)

from Apico LLC 5,069 4,537 5,497 4,007 2,563 4,436 4,272 3,256 Net income (loss) before non-

controlling interests 94,900 41,051 43,504 48,493 19,249 18,999 12,408 (2,016)Non Controlling interest (882) (951) (1,354) (358) (357) 14 (592) (346)Net income (loss) attributable

to Coastal Energy Company 94,018 40,100 42,150 48,135 18,892 19,013 11,816 (2,362)

EBITDAX(a) $121,552 $114,603 $130,278 $128,439 $75,085 $44,658 $39,467 $42,479Basic earnings (loss) $0.83 $0.35 $0.37 $0.42 $0.17 $0.17 $0.11 ($0.02)Diluted earnings (loss) $0.80 $0.34 $0.36 $0.40 $0.16 $0.16 $0.10 ($0.02)

Note (a) EBITDAX is a non-IFRS and non-Canadian GAAP measure and is defined as earnings before interest, financing fees,

taxes, depreciation, amortization, exploration costs and other one-time items 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 (see reconciliation above).

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Significant factors influencing Quarterly Results include:• The volatility of global crude oil prices has a direct

effect on the Company’s 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 2012 due to a full year of Bua Ban North operating expenses. The Company has taken steps to reduce these operating costs by purchasing production facilities and equipment that was previously leased from third parties.

• The Company has incurred higher general and administrative expenses as the substantial increase in the Company’s stock price has increased its Share-Based Compensation expense as well as the accrual value of stock-linked cash compensation.

• The Company transacts business in multiple currencies; therefore, the volatility of global currency exchange rates has a direct effect on the Company’s foreign exchange (gains) losses.

Cash Flow AnalysisThe Company’s cash and cash equivalents at December 31, 2012, were $63.9 million, an increase of $40.9 million from $23.0 million at December 31, 2011. The Company’s primary source of funds came from operations and $50.0 million of borrowings. Cash and cash equivalents were primarily used to fund property, plant and equipment expenditures of $309.6 million, $9.3 million to cover the acquisition of an increased stake in Apico LLC, $30.0 million in debt reduction payments, $18.8 million to repurchase the Company’s own stock and $31.1 million to cover cash settlement of stock options. The residual was used to fund working capital.

Capital ExpendituresCapital expenditures (on an accruals basis) amounted to $368.1 million in 2012, compared to $153.5 million in 2011, respectively. The 2012 expenditures were related to exploration, appraisal and development drilling as well as a 3D seismic survey that was performed over the Company’s entire offshore acreage position in 2012. The following table sets forth a summary of the Company’s capital expenditures incurred:

capital expenditures


2012 2011Seismic, geological and

geophysical studies $41,488 $5,145Drilling and completions 124,279 113,337Facilities 163,096 6,081Lease and well equipment 38,047 27,839Administrative assets $1,155 1,133Total Capital Expenditures $368,065 $153,535

Equity Capital

Share CapitalAuthorized 250,000,000 common shares with par value of $0.04 each;

As of the date of this report, the Company had 113,604,820 common shares outstanding.

During 2012 the Company instituted a Normal Course Issuer Bid (“NCIB”) to repurchase its common shares through the Toronto Stock Exchange. The NCIB covers 5% (5,715,972) of the shares outstanding immediately prior to the program being undertaken. As of the date of this report, the Company has repurchased 1,295,450 shares at an average price of C$14.48 per share. The number repurchased equates to 1% of the number of shares outstanding on January 1, 2012.

WarrantsAs of December 31, 2012, the Company had 200,000 warrants outstanding, exercisable at CAD $1.136 per share. During the twelve months ended December 31, 2012, no warrants were exercised.

Subsequent to December 31, 2012, no warrants were exercised, resulting in the issuance of no common shares of the Company.

Stock OptionsDuring the year ended December 31, 2012, the Company did not grant any stock options. Over the same period, 3,234,978 options were exercised (2,141,359 of those exercised were settled by the Company for cash in the aggregate amount of $31.7 million), whereas 14,250 options were forfeited. As of December 31, 2012, the Company had 5,296,219 stock options outstanding with a weighted average exercise price of $7.16. Subsequent to December 31, 2012, 231,594 options were exercised and no options were forfeited. As of the date of this report, the following ISOs were outstanding:

20

Grant DateNumber

OutstandingRemaining

Contractual LifeExercise

PriceExpiry

DateNumber

ExercisableSep. 16, 2008 100,000 0.50 years $2.31 (Cdn$2.28) Sep. 16, 2013 100,000Jan. 02, 2009 739,583 0.75 years $1.37 (Cdn$1.36) Jan. 01, 2014 739,583Dec. 01, 2009 1,628,885 1.75 years $5.22 (Cdn$5.16) Nov. 30, 2014 1,628,885Dec. 28, 2010 1,163,444 2.75 years $5.85 (Cdn$5.78) Dec. 27, 2015 670,748Dec. 14, 2011 1,432,713 3.75 years $14.27 (Cdn$14.11) Dec. 13, 2016 407,662

5,064,625 3,546,878

Restricted stock unitsDuring the year ended December 31, 2012, 509,963 restricted stock units were granted and 41,735 were settled. As of December 31, 2012, the Company had 673,856 restricted stock units outstanding. Subsequent to

December 31, 2012, a further 26,800 restricted stock units were settled.

The following table summarizes the outstanding RSUs as of the date of this report:

GrantDate

NumberOutstanding

RemainingContractual Life

Grant Date Fair Value

ExpiryDate

Dec. 14, 2011 137,093 2 years $12.93 Dec. 14, 2014Dec. 14, 2012 509,963 3 years $19.87 Dec. 14, 2015

647,056

Off-Statement of Financial Position ArrangementsThe Company has no off-statement of financial position arrangements.

Related Party TransactionsIn 2012, a related party of the primary shareholder, O.S. Wyatt, Jr., reached payout under the terms of a net profits agreement following the recovery of all capital and operating expenditures relating to the G5/43 concession. Under the terms of this arrangement, the Company paid $0.65 million and accrued a further $0.10 million at December 31, 2012. These amounts are based upon 2.5% of net profits from the Gulf of Thailand Block G5/43 operations. The net profits agreement was executed in 2005 and has been previously disclosed by the Company.

In accordance with the rules of the Toronto Stock Exchange, information concerning directors’ remuneration will be detailed in regulatory news filings and in the proxy document for the Company’s Annual General Meeting. The details contained therein are also in compliance with London-AIM listing requirements.

Commitments and Contingencies All the Company’s commitments and contingencies are described in Note 20 to the Consolidated Financial Statements for the year ended December 31, 2012.

Subsequent EventsThe Company has no material subsequent events.

Critical Accounting Policies, Estimates and New Accounting PronouncementsA detailed summary of the Company’s critical accounting policies and estimates is included in Note 3 to the audited financial statements for the twelve months ended December 31, 2012.

Risks and UncertaintiesCoastal has published its assessment of its business risks in the Risk Factor section of its Annual Information Form (“AIF”) dated March 26, 2013 (available on SEDAR at www.sedar.com). It is recommended that this document be reviewed for a thorough discussion of risks faced by the Company.

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.

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IndustryThe 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.

Petroleum and Gas PricesIn recent years, the petroleum and natural gas exploration industry has seen significant 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 oilfields. However, with improving prices 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, fluctuations in the U.S. dollar and other currencies, interest rates and inflation. Continued volatility in commodity prices may adversely affect the Company’s operating cash flow.

Operating Hazards and RisksExploration 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 significant costs that could have a material adverse effect upon its financial condition.

Reserve EstimatesDespite the fact that the Company has reviewed the estimates 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 figures 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 profitability 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 ProductionOther factors affecting the production and sale of oil and natural gas that could result in decrease of profitability 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 difficulties; (v) worker vacation schedules and related maintenance activities; and (vi) changes in the market and general economic conditions. Weather conditions, equipment replacement or repair, fires, amounts of rock and other natural materials and other geological conditions can have a significant impact on operating results.

Cash Flows and Additional Funding RequirementsThe 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 presently available to the Company for development are cash flow from production or the issuance of debt or equity. The Company has sufficient financial resources to undertake its firm obligations for the next 12 months.

The Company is exposed to fluctuations 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 flexible in borrowing and repaying the outstanding balances.

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EnvironmentalThe Company’s 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.

Laws and RegulationsThe Company’s 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 or can become more stringent, and therefore compliance can 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 office 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 operations in 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 fluctuations. These risks include: political and economic instability or war; the possibility that a foreign government may seize our property with or without compensation; confiscatory 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; fluctuating 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 PropertiesWhile the Company has undertaken customary due diligence in the verification of title to its oil and gas properties, this should not be construed as a guarantee of title. The properties may be subject to prior unregistered Petroleum Agreements or transfers and title may be affected by undetected defects.

Dependence on ManagementThe 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 ReportingThe Company accounts for its 39.0% investment in Apico (2011: 36.1%) under the equity method whereby it records its share of Apico’s earnings as earnings from a significantly influenced investee. Apico is required to provide the partners its financial 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 control the Board or the management of Apico. Therefore, the Company relies heavily on Apico management to provide timely and accurate financial information to the partners.

Risk Management and Financial InstrumentsCoastal provides a risk management and financial instruments discussion on its exposure to and management of credit risk, liquidity risk and market risk in Note 24 to the audited financial statements as at and for the period ended December 31, 2012 and 2011.

23

Management’s Report on Internal Control over Financial Reporting

Disclosure Controls and Procedures:The Company’s 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 defined under National Instrument 52 – 109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”). Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in reports filed 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 Company’s disclosure controls and procedures are effective as of December 31, 2012.

Internal Controls over Financial ReportingThe Company’s management, with the participation of its CEO and CFO, are responsible for establishing and maintaining adequate internal controls over financial reporting (“ICFR”). Under the supervision of the CFO, the Company’s ICFR is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial 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 financial statement preparation and presentation. As at the end of the period covered by this Management’s Discussion and Analysis, management evaluated the effectiveness of the Company’s 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 period covered by this Management’s Discussion and Analysis, the ICFR were designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.

OutlookIn 2013, the Company plans to continue development and appraisal drilling on its existing assets in the Gulf of Thailand. The Company has development drilling activities planned at Bua Ban North and South and Songkhla A & Songkhla H. The Company also plans to drill several exploration wells, including a commitment well on Block G5/50 during 2013.

The full interpretation of the 3D seismic survey acquired during the second half of 2012 will be delivered to the Company during 2013, and the Company expects it to generate additional exploration prospects on its assets.

The Company plans to reach its target of first oil from the Kapal field in Malaysia in mid-2013.

25

M a n a g e M e n t ’ S r e p o r t

Management is responsible for the integrity and objectivity of the information contained in this report and for the consistency between the consolidated financial statements and other financial and operating data contained elsewhere in this report. The accompanying consolidated financial 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 consolidated financial statements have been prepared using policies and procedures established by management and fairly reflect the Company’s financial position, financial performance and cash flows, 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 financial information is reliable and accurate.

The Company’s external auditors, Deloitte, LLP, have audited the consolidated financial statements. Their audit provides an independent view as to management’s discharge of its responsibilities insofar as they relate to the fairness of reported financial results and the financial performance of the Company.

The Audit Committee of the Board of Directors have reviewed in detail the consolidated financial statements with management and have met with the external auditors. The Audit Committee has reported its findings to the Board of Directors, who have approved the consolidated financial statements.

/s/ Randy Bartley /s/ William Phelps President & Chief Executive Officer Chief Financial Officer

Houston, Texas USA March 23, 2013

26

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

To the Shareholders of Coastal Energy Company:We have audited the accompanying consolidated financial statements of Coastal Energy Company, which comprise the consolidated statements of financial position as at December 31, 2012 and December 31, 2011, and the consolidated statements of operations and comprehensive income, the consolidated statement of changes in equity and consolidated statements of cash flow for the years ended December 31, 2012 and December 31, 2011, and the notes to the consolidated financial statements.

Management’s Responsibility for the Consolidated Financial StatementsManagement is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s ResponsibilityOur responsibility is to express an opinion on these consolidated financial 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 consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial 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 entity’s 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 financial statements.

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

OpinionIn our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Coastal Energy Company as at December 31, 2012 and December 31, 2011, and its financial performance and its cash flows for the years then ended in accordance with International Financial Reporting Standards.

Chartered Accountants March 26, 2013 Calgary, Alberta

27

C o n S o l I d a t e d S t a t e M e n t S o f o p e r a t I o n S a n d C o M p r e h e n S I v e I n C o M e u S $ 0 0 0 s

Years Ended December 31, 2012 2011 revenues and other income

Oil sales 746,853 347,783 Royalties (79,280) (29,113)Oil sales, net of royalties 667,573 318,670 Reimbursement of expenses under Malaysia risk service contract (Note 3) 4,099 - Other income (Note 16) (4,770) (21,566)

666,902 297,104

expensesProduction 149,999 99,263 Malaysia risk service contract (Note 3) 4,099 - Depreciation and depletion (Note 8) 70,139 61,136 Net profits interest (Note 18) 1,041 - General and administrative 39,696 31,453 Exploration (Note 7) 7,477 8,374 Debt financing fees 2,165 796 Finance (Note 15) 4,715 4,825 Gains on disposal of property, plant and equipment (252) (873)

279,079 204,974

Net income before income taxes and share of earnings from apico llc 387,823 92,130

Share of earnings from Apico LLC (Note 9) 19,110 14,527

Net income before income taxes 406,933 106,657

income taxes (Note 21)Current 150,329 135 Deferred 28,656 57,882

178,985 58,017

Net income and comprehensive income 227,948 48,640

Net income and comprehensive income attributable to:Shareholders of Coastal Energy 224,403 47,359 Non-controlling interests 3,545 1,281

227,948 48,640

Net income per share:Basic (Note 19) 1.98 0.42 Diluted (Note 19) 1.92 0.41

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

28

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 u S $ 0 0 0 s

As at

December 31, 2012

December 31, 2011

$ $ assets

current assetsCash 63,897 22,995 Restricted cash (Note 4) 6,452 28,447 Accounts receivable (Note 5) 56,848 16,939 Derivative asset (Note 12) 132 59 Inventories (Note 6) 20,856 14,161 Prepaids and other current assets 628 1,094

Total current assets 148,813 83,695

Non-current assetsExploration and evaluation assets (Note 7) 123,574 31,881 Property, plant and equipment (Note 8) 555,269 355,052 Investment in and advances to Apico LLC (Note 9) 60,266 47,698 Deposits and other assets 6,271 405

Total non-current assets 745,380 435,036 total assets 894,193 518,731

liabilitiescurrent liabilities

Accounts payable and accrued liabilities (Note 10) 131,005 59,392 Income taxes payable (Note 21) 86,752 79 Current portion of long-term debt (Note 12) 34 55,662 Current portion of derivative liabilities (Note 12) 1,372 14,557

Total current liabilities 219,163 129,690 Non-current liabilities

Long-term debt (Note 12) 95,066 22,156 Derivative liabilities (Note 12) 502 1,274 Derivative liability - Warrants (Note 11) 3,784 2,853 Deferred tax liabilities 98,423 69,767 Decommissioning liabilities (Note 13) 46,726 42,124

Total Non-Current Liabilities 244,501 138,174 shareholders’ equity (Note 19)

Common shares 213,260 211,554 Contributed surplus 18,940 16,401 Retained earnings 193,877 17,630

Total Shareholders’ Equity 426,077 245,585 Non-controlling interests 4,452 5,282

total equity 430,529 250,867 total liabilities and equity 894,193 518,731

Commitments and contingencies (Note 20) The accompanying notes are an integral part of these consolidated financial statements.

Approved by the Board

/s/ Randy Bartley /s/ Lloyd Barnaby SmithRandy L. Bartley, Director Lloyd Barnaby Smith, Chairman

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C o n S o l I d a t e d S t a t e M e n t S o f C a S h f l o w S u S $ 0 0 0 s

Years Ended December 31, 2012 2011 operating activities

Net income 227,948 48,640 Adjustments:

Share of earnings from Apico LLC (19,110) (14,527)Unrealized gain on derivative financial instruments (14,030) (843)Depletion and depreciation 70,139 61,136 Finance expense 4,715 4,825 Amortisation of debt financing fees 1,322 786 Share-based compensation 14,190 15,185 Deferred income taxes 28,656 57,882 Unrealized foreign exchange (gain) loss (885) 388 Exploration expense 7,477 8,374 Gains on disposal of property, plant and equipment (252) (873)

Income taxes paid (63,656) (86)Interest received 39 6 Interest paid (2,994) (4,022)Dividends received from Apico LLC 15,792 15,536 Change in non-cash working capital:

Accounts receivable (39,909) (6,640)Inventory (6,695) (1,378)Prepaids and other curent assets 466 (488)Accounts payable and accrued liabilities 71,574 4,899

Current income taxes payable 86,673 48 Cash flow provided by operating activities 381,460 188,848 financing activities

Issuance of common shares, net of issuance costs 3,314 7,907 Repurchase of common shares (18,753) - Cash settlement of stock options (31,136) - Cash settlement of restricted stock units (663) - Borrowings under long-term debt 50,000 6,275 Repayment of long-term debt (30,000) - Debt financing fees (4,074) (594)Payments to non-controlling interest (4,375) (2,558)Other - (506)

Cash flow (used) provided by financing activities (35,687) 10,524 investing activities

Decrease (increase) in restricted cash 21,995 (12,078)Purchase of property, plant and equipment (309,599) (165,099)Acquisition of increased ownership interest in Apico LLC (9,250) - Advances to Apico LLC - (1,446)Proceeds from disposal of property, plant and equipment 352 250 Deposits and other assets - Payments (6,000) (116)Deposits and other assets - Refunds 134 -

Cash flow used in investing activities (302,368) (178,489)Effect of exchange rate changes on cash (2,503) (1,772)Increase in cash 40,902 19,111 Cash - Beginning of year 22,995 3,884 cash - end of year 63,897 22,995


30

C o n S o l I d a t e d S t a t e M e n t o f C h a n g e S I n e Q u I t y u S $ 0 0 0 s

NoteCommon

SharesContributed

Surplus Warrants

Retained earnings /

(accumulated deficit)

Attributable to

shareholders of Coastal

Energy Company

Non-Controlling

Interests Total

$ $ $ $ $ $ $balance as at

January 1, 2011 22 201,303 15,971 - (29,729) 187,545 6,559 194,104

Net income and comprehensive income - - - 47,359 47,359 1,281 48,640

Exercise of stock options 10,201 (2,294) - - 7,907 - 7,907 Exercise of warrants 50 - (50) - - - - Share-based compensation - 2,774 - - 2,774 - 2,774 Transfer to contributed

surplus - (50) 50 - - - - Distributions declared to

non-controlling interest - - - - - (2,558) (2,558)Balance as at

December 31, 2011 22 211,554 16,401 - 17,630 245,585 5,282 250,867

Net income and comprehensive income - - - 224,403 224,403 3,545 227,948

Exercise of stock options 4,190 (876) - - 3,314 - 3,314 Shares repurchased and

cancelled (2,484) - - (16,269) (18,753) - (18,753)Stock options purchased and

cancelled - (2,204) - (31,659) (33,863) - (33,863)Restricted stock units

purchased and cancelled - (435) - (228) (663) - (663)Share-based compensation - 6,054 - - 6,054 - 6,054 Distributions declared to

non-controlling interests - - - - - (4,375) (4,375)balance as at

December 31, 2012 22 213,260 18,940 - 193,877 426,077 4,452 430,529


31

n o t e S t o t h e C o n S o l I d a t e d f I n a n C I a l S t a t e M e n t S (All tabular amounts are expressed in US $000s unless otherwise stated except share and per share amounts.)

Note 1. Reporting entityCoastal Energy Company (“Coastal” or the “Company” or “we”) is an international oil and gas exploration and development company with operations in offshore Thailand and Malaysia, and an interest in a joint venture which operates in northeastern Thailand. The Company’s shares are widely held and publicly traded on the Toronto Stock Exchange (TSX) and the London Alternative Investment Market (AIM).

The Company’s head office is at Walkers House, 87 Mary Street, George Town, Grand Cayman, KY1-9001, Cayman Islands. The Company’s domicile is the Cayman Islands.

Note 2. Basis of presentation

Statement of complianceThese consolidated financial statements have been prepared in accordance with IFRS as issued by the International Accounting Standards Board effective as of December 31, 2012.

These consolidated financial statements were authorized for issue by the Company’s Board of Directors on March 26, 2013.

Basis of measurementThe Company prepared these consolidated financial statements on a going concern basis, which contemplates the realization of assets and liabilities in the normal course of business as they become due. Accordingly, these consolidated financial statements have been prepared on the historical cost basis, except for cash, restricted cash, derivative financial instruments and share-based payment transactions that have been measured at fair value.

The consolidated statements of operations and comprehensive income have been grouped on a function basis.

Functional and presentational currencyThese consolidated financial statements are presented in United States dollars, which is both the functional and presentation currency of the Company and its subsidiaries, and all amounts are represented in hundreds of thousands United States dollars except when otherwise indicated.

Accounting judgments and estimation uncertaintyThe preparation of financial statements in conformity with IFRS requires management to make estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Estimates and underlying assumptions are reviewed on a regular basis and are based on management’s experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances.

In preparing these consolidated financial statements, the Company makes judgments regarding the application of its accounting policies. Significant judgments relate to the capitalization and depletion of oil and gas exploration and development costs and the identification of cash-generating units.

The financial statement areas that require significant estimates and assumptions are included in the following notes:

Oil and Gas Accounting – Reserve DeterminationThe process of estimating reserves is complex. It requires significant estimates based on available geological, geophysical, engineering and economic data. To estimate the economically recoverable crude oil and natural gas reserves and related future net cash flows, the Company incorporates many factors and assumptions, including the expected reservoir characteristics, future commodity prices and costs and assumed effects of regulation by governmental agencies. Reserves are used to calculate the depletion of the capitalized oil and gas development costs and for impairment purposes as described in Note 3.

32

Asset ImpairmentsFor impairment testing of property, plant and equipment and exploration and evaluation assets, the assessment of facts and circumstances is a subjective process that often involves a number of estimates and is subject to interpretation. One of the more significant policies adopted by Coastal has been deciding the level at which assets are to be aggregated for assessing impairment. These groupings are referred to as cash-generating units (“CGU”). Based on numerous factors, including the independence of cash inflows and production infrastructure, management considers the Company to have two CGUs, namely onshore and offshore Thailand.

The testing of assets or CGU’s for impairment, as well as the assessment of potential impairment reversals, requires estimates of an asset’s or CGU’s recoverable amount. The estimate of a recoverable amount requires a number of assumptions and estimates, including quantities of reserves, expected production volumes, future commodity prices, discount rates as well as future development and operating costs. These assumptions and estimates are subject to change as new information becomes available and changes in any of the assumptions, such as a downward revision in reserves, a decrease in commodity prices or an increase in costs, could result in an impairment of an asset’s or CGU’s carrying value.

At December 31, 2012, the recoverable amounts of the Company’s CGU’s were estimated as their fair value less cost to sell based on the net present value of the pre-tax cash flows from oil and gas reserves of each CGU that are based on reserves estimated by the Company’s independent reserve evaluator.

Key input estimates used in the determination of cash flows from oil and gas reserves include the following:

(i) Reserves Assumptions that are valid at the time of reserve estimation may change significantly when new information becomes available. Changes in forward price estimates, production costs or recovery rates may change the economic status of reserves and may ultimately result in reserves being restated.

(ii) Oil and natural gas prices Forward price estimates of the oil and natural gas prices are used in the cash flow model. Commodity prices have fluctuated widely in recent years due to global and regional factors, including supply and demand fundamentals, inventory levels, exchange rates, weather, economic and geopolitical factors.

(iii) Discount rate The discount rate used to calculate the fair value of cash flows is based on estimates of an approximate industry peer group weighted average cost of capital. Changes in the general economic environment could result in significant changes to this estimate. Impairment tests were carried out at December 31, 2012, and were based on fair value less costs to sell calculations, using a pre-tax discount rate of 10 per cent and the following forward commodity price estimates:

YearBrent Crude Oil

(US$/bbl)2013 108.002014 102.002015 98.002016 95.002017 97.00Remainder Escalated at 2% thereafter

For the year ended December 31, 2012, the Company did not record any impairment (2011: $nil).

33

Decommissioning LiabilitiesIn estimating future decommissioning liabilities, assumptions are made about activities that occur many years into the future, including the cost and timing of such activities. Additionally, interpretation of contracts and regulations is required by management as to what constitutes removal and remediation. The ultimate financial impact is not clearly known as asset removal and remediation techniques and costs are constantly changing, as are legal, regulatory, environmental, political, safety and other such considerations. In arriving at amounts recorded, numerous assumptions and estimates are made on ultimate settlement amounts, inflation factors, discount rates, timing and expected changes in legal, regulatory, environmental, political and safety environments.

Commitments, Contingencies and GuaranteesBy their nature, contingencies will only be resolved when one or more future events transpire. The assessment of contingencies inherently involves estimating the outcome of future events.

Income TaxesThe Company has subsidiaries in Thailand, Malaysia, Mauritius, the United States and the United Kingdom, which are subject to income taxes in these jurisdictions. The Company is also subject to Special Remuneratory Benefit (“SRB”) in Thailand. The determination of income tax and SRB tax is inherently complex, and the Company is required to interpret continually changing regulations and make certain estimates and assumptions about future events. While income tax filings are subject to audits and reassessments, the Company believes it has adequately provided for all income tax obligations. However, changes in facts and circumstances as a result of income tax audits, reassessments, jurisprudence and any new legislation may result in an increase or decrease in the provision for income taxes.

Fair Value Measurements A number of the Company’s accounting policies and disclosures require the determination of fair value for both financial and non-financial assets and liabilities. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that asset or liability.

The fair value of accounts receivables, accounts payable and accrued liabilities approximate their carrying value due to their short term to maturity.

Warrants, if converted by the holder, are settled in common shares at the option of the holder, the number of which may vary. This obligation results in a derivative liability in accordance with IFRS standards. As a result of measuring the liability at fair value under IFRS, fluctuations in the estimated fair value will affect the derivative liability gains and losses that are recognized. The fair value of the liability is determined using the Black-Scholes valuation model, which is based on the year end share price and the exercise price of the warrants, and assumptions for the risk-free interest rate (based on government bonds), expected dividends and the volatility of the share price (based on the implied volatilities of options traded in the open market, the volatility of the U.S. and Canadian Dollar and expected correlation). The actual settlement of the derivative liability could differ materially from the fair value recorded and could impact future results.

The fair value of derivative financial instruments is based upon quotations provided by several financial institutions.

The fair value of share-based compensation is estimated using the Black-Scholes valuation model. The inputs are based on factors including the share price on measurement date and the exercise price of the instrument, and based on assumptions for the risk-free interest rate (based on government bonds), the forfeiture rate and expected life of the instruments (based on historical experience and general option holder behaviour), expected dividends and the volatility of the share price (based on historic movements in the Company’s share price).

34

Note 3. Significant accounting policies

Significant accounting policiesThe accounting policies set out below were used to prepare these consolidated financial statements.

ConsolidationThese consolidated financial statements include the accounts of the Company and its controlled subsidiaries. All subsidiary companies are wholly owned with the exception of Viking Storage Solutions (Mauritius) Limited (“VSS”) and Coastal Energy KBM Sdn. Bhd. (“KBM”), upon which non-controlling interests arise. All intercompany balances, revenues and expenses are eliminated upon consolidation.

Coastal also has a 39% (2011: 36.1%) interest in Apico LLC, an associate accounted for under the equity method. Apico LLC is involved in the exploration and production of gas in Northeastern Thailand.

The table below summarizes the Company’s ownership in other entities:

Name Ownership interest Type Country of IncorporationCoastal Energy Company Nevada 100% Subsidiary United StatesCoastal Energy (UK) Company Limited 100% Subsidiary United KingdomNuCoastal (Thailand) Limited 100% Subsidiary ThailandCoastal Energy Company (Khorat) Ltd 100% Subsidiary Cayman IslandsMOPU Holdings Limited 100% Subsidiary Cayman IslandsCEC International Limited 100% Subsidiary Cayman IslandsMOPU Holdings (Singapore) Pte. Limited 100% Subsidiary SingaporeCEC Services (Thailand) Limited 100% Subsidiary ThailandOcean 66 Limited 100% Subsidiary MauritiusCoastal Energy KBM Sdn. Bhd. 70% Subsidiary MalaysiaViking Storage Solutions (Mauritius) Limited 50% Subsidiary MauritiusApico LLC 39% Partnership United States

The comments below detail facts pertinent to the determination of the appropriate consolidation treatment of the aforementioned entities:

Interests in wholly owned subsidiariesFor all of the wholly owned entities, the Company can select 100% of the respective board of directors and holds 100% of the voting rights. Therefore, there are no significant restrictions on the Company’s ability to control assets or settle liabilities of those wholly owned subsidiaries beyond those detailed in Note 4.

Interest in Coastal Energy KBM Sdn. Bhd (subsidiary)The Company holds 70% of the shares in KBM, maintains 70% of the voting rights and is able to elect two-thirds of the board of directors with the residual relating to the non-controlling interest. The incorporation of this entity occurred in 2012 in order to administer the Company’s risk service contract in offshore Malaysia.

The non-controlling interest credit related to KBM was $0.08 million in 2012, with the December 31, 2012 accumulated non-controlling interest being $0.08 million receivable.

The following table summarizes KBM’s assets and liabilities:

As atDecember

31, 2012Current assets $4,461Non-current assets 7,000Current liabilities 7,121Non-current liabilities -

35

The following table summarizes KBM’s revenue and net income:

Years ended December 31, 2012Revenue $4,131 Net loss (253)

Interest in Viking Storage Solutions (Mauritius) Limited (subsidiary)The Company holds 50% of the shares in VSS, maintains 50% of the voting rights and is able to elect 50% of the board of directors, with the residual relating to the non-controlling interest. The incorporation of this entity occurred in 2009 in order to obtain external financing that would enable the construction of a single storage vessel to be used in the Company’s offshore Thailand operations. This storage vessel is currently being leased under a bareboat charter to CEC International Limited, the entity which holds the Company’s offshore Thailand operations. Given the nature of the bareboat charter, the Company can actively control how the storage vessel is controlled.

The non-controlling interest charge related to VSS was $3.62 million in 2012 (2011: $1.28 million), with the December 31, 2012 accumulated non-controlling interest being $4.52 million credit ($5.28 million credit).

The following table summarizes VSS’s assets and liabilities:

As atDecember

31, 2012December

31, 2011Current assets $9,994 $7,626Non-current assets 21,091 24,104Current liabilities 1,619 1,368

The following table summarizes VSS’ revenue and net income:

Years ended December 31, 2012 2011Revenue $11,704 $10,409 Net income 8,262 2,923

Interest in Apico LLC partnershipThe Company owns a 39% interest (2011: 36.1%) in Apico LLC partnership, holds 39% of the voting rights and can nominate one of the three board of director seats. However, given ‘substantial decisions’ requires 75% of the partners to agree and there are several combinations in which this can be achieved, all of which include the Company, the Company cannot exercise control or joint control. As such, treatment as an associate is appropriate.

For the avoidance of doubt, ‘substantial decisions’ would amongst other things include those concerning dividend payments, granting of additional shares, approval of budgets and dissolution of the partnership.

Further information on Apico LLC can be found in Note 9.

Revenue RecognitionRevenues from the sale of crude oil and natural gas liquids are recognized when:

• The Company has transferred the significant risks and rewards of ownership to the buyer (title transfer);

• The Company retains no continuing managerial involvement to the degree usually associated with ownership or effective control over the goods sold;

• The amount of revenue can be measured reliably;

• It is probable that the economic benefits associated with the transaction will flow to the Company; and

• The costs incurred or to be incurrent in respect of the transaction can be measured reliably.

Revenue is presented net of royalties.

36

Revenue and expense recognition under the risk service contractThe nature of risk service contract (“RSC”) with Petronas in Malaysia is discussed in Note 20. Under the RSC there are essentially three revenue streams: reimbursement of capital expenditures (‘construction revenue’), reimbursement of operating costs and a remuneration fee based on each barrel produced. Revenue earned through to December 31, 2012 all relates to construction revenue since production has yet to commence.

Construction revenue relates to the exploration and field development activities under the RSC. Construction revenue represents the sales value of work done in the year, including fees invoiced and estimates in respect of total amounts to be invoiced after the year end. Revenue is recognized based on the percentage of completion method, where the percentage of completion method is based upon the proportion of costs incurred relative to the total estimated cost. Full provision would be made for all known or anticipated losses at the time such losses are forecast.

Revenue under the RSC is presented gross of expenditures on the face of the income statement in accordance with IAS 1 Presentation of financial statements.

Finance Expense Finance expense comprises interest expense on borrowings, accretion on decommission liabilities, interest on finance leases and changes in the fair value of warrants.

Borrowing costs directly related to the acquisition, construction or production of a qualifying asset under construction for greater than one year are capitalized and added to the project cost during construction until such time that the assets are substantially ready for their intended use. Where funds are borrowed specifically to finance a project, the amount capitalized represents the actual borrowing costs incurred less interest income earned. Any income generated from short-term investments reduces the related total capitalized borrowing costs. The Company did not capitalize any borrowing costs in 2012 or in 2011.

Foreign Currency TranslationThe United States dollar is the functional currency of the Company and its subsidiaries. Monetary assets and liabilities denominated in a currency other than the functional currency are translated at the exchange rate in effect at the reporting period date. Non-monetary assets, liabilities, revenues and expenses are translated at transaction date exchange rates. Exchange gains or losses are included in the determination of net income as foreign exchange gains or losses.

Exploration and evaluation (E&E) ExpendituresExploration and evaluation assets include all costs directly associated with the exploration and evaluation of crude oil and gas reserves. Such costs may include costs of license acquisition, technical services and studies, decommissioning liabilities and exploration drilling and testing.

E&E assets are initially capitalized on an area-by-area basis. When an E&E area is determined to be technically feasible and commercially viable, the accumulated costs are transferred to property, plant and equipment subject to an impairment test. When an area is determined not to be technically feasible and commercially viable or the Company decides not to continue with its activity, the unrecoverable costs are charged to net income as exploration and evaluation expense.

Property, plant and equipment (PP&E) PP&E costs are classified as assets under construction, oil & gas properties and corporate & other assets.

Oil & gas properties include all costs directly associated with the development of crude oil and gas reserves. These expenditures include proved property acquisitions, development drilling and completions, gathering and infrastructure, decommissioning liabilities and transfers from exploration and evaluation assets where technical feasibility and commercial viability has been determined.

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Oil & gas properties are capitalized on an area-by-area (“component”) basis, with ‘area’ referring to each prospect. Costs accumulated within each area’s components are depleted using the unit-of-production method based on proved plus probable reserves using estimated future prices and costs. Costs subject to depletion include estimated future costs to be incurred in developing proved and probable reserves. Costs of major development projects are excluded from the costs subject to depletion until they are available for use. For divestitures of properties, a gain or loss is recognized in net income.

Corporate & other assets consist mainly of computers, software and office furniture and equipment. Depreciation of corporate assets is calculated on a straight line basis over the useful life of the related assets. The useful life of such items is 3-17 years.

Maintenance and RepairsExpenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred.

ImpairmentWhen an E&E area is determined to be technically feasible and commercially viable, the accumulated costs are transferred to property, plant and equipment. E&E costs are tested for impairment at the time of transfer, and any unrecoverable costs are charged to net income as exploration and evaluation expense.

E&E and PP&E costs are accumulated on an area-by-area basis then grouped into CGU’s on the basis of geographical area having regard to the operational infrastructure (such as facilities and sales points) of the area, and are the lowest level at which there are identifiable cash inflows that are largely independent of the cash flows of other groups of assets. The Company currently has two CGU’s: Onshore and Offshore Thailand.

For impairment test purposes, corporate assets are allocated to each of the CGU’s on the basis of proportionate future net revenue consistent with the recoverable amount.

At the end of each reporting period, the Company assesses the CGU’s for circumstances that indicate that the assets may be impaired. If any such indication of impairment exists, the Company makes an estimate of its recoverable amount. A CGU’s recoverable amount is the higher of its fair value less costs to sell and its value in use. Where the carrying amount of an asset or CGU’s group exceeds its recoverable amount, the asset or CGU is considered impaired and is written-down.

For impairment losses identified based on a CGU, or group of CGU’s, the loss is allocated on a pro rata basis to the assets within the CGU(s). The impairment loss is recognized as an expense in the statement of operations.

Where the circumstances that gave rise to an impairment loss subsequently reverses, the carrying amount of the asset (or CGU) is increased to the revised estimate of its recoverable amount, so that the revised carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognized for the asset (or CGU) in prior years. A reversal of an impairment loss is recognized immediately in the statement of operations.

Investment in and advances to Apico LLCThe results, assets and liabilities of Apico LLC (“Apico”) are incorporated in these consolidated financial statements using the equity method of accounting. Under this method, the investment is carried in the consolidated statement of financial position at cost, plus post-acquisition changes in the group’s share of net assets of Apico LLC, less distributions received and less any impairment in value of the investment. The Company’s income statement reflects Coastal’s share of the results after tax of Apico. The financial statements of Apico are prepared for the same reporting period as for the Company. Where necessary, adjustments are made to those financial statements to bring the accounting policies used into line with those of the group.

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Decommissioning LiabilitiesThe Company recognizes the estimated fair value of decommissioning liabilities associated with PP&E and E&E assets as a liability in the year in which they are incurred, normally when the asset is purchased or developed. The fair value is capitalized and amortized over the same period as the underlying asset. The Company estimates the liability based on the estimated costs to abandon and reclaim the wells and well sites that are required to be abandoned under the terms of oil and gas contracts. Wells and well sites that the Company has acquired, constructed, drilled, completed workovers on, or performed enhancements to are included in the estimate. This estimate is evaluated on a periodic basis, and any adjustment to the estimate is applied prospectively. The change in net present value of the future decommissioning liabilities due to the passage of time is expensed as unwinding of the discount. Actual decommissioning liabilities settled during the year reduce the decommissioning liability.

Earnings Per ShareThe Company computes basic earnings per share using net income divided by the weighted-average number of common shares outstanding. The Company computes diluted earnings per share using unadjusted net income, divided by the weighted-average number of diluted common shares outstanding. The Company uses the treasury stock method in computing the weighted-average number of diluted common shares outstanding. This method assumes that the proceeds on exercise of in-the-money stock options, deferred common shares and incentive shares are used to repurchase the Company’s common shares at the average market price during the relevant year. The number of diluted common shares outstanding also reflects the potential dilution that would occur if the stock options and restricted stock units were converted into common shares at the beginning of the year, or when they were issued.

Share-Based CompensationThe Company uses the fair value method of accounting for all equity-based awards to non-employees and employees, including those that are direct awards of stock. Under the fair value method, share-based compensation expense attributed to direct awards of stock is measured at the fair value of the award at the grant date using the Black-Scholes option-pricing model and is recognized over the vesting period of the award. If and when the stock options are ultimately exercised by the recipient of the awards, or the restricted stock units vest, the applicable amounts of contributed surplus are credited to share capital.

The Company awards cash-settled stock appreciation rights (“SARs”) to its employees. The compensation cost for the granted SARs is accounted for using the fair value method. Under this method, the Company accrues a liability based on the fair value derived from the Black-Scholes option-pricing model of the SARs vested. The accrued liability is adjusted at each statement of financial position date for the effect of SAR grants, vesting of SARs, SARs exercised, as well as the effect of changes in the underlying price of the Company’s common shares. The offsetting entry is expensed or capitalized depending on the role performed by the employee.

Deferred TaxesThe Company accounts for deferred taxes using the balance sheet liability method. Under this method, the Company records a deferred tax asset or liability to reflect any temporary difference between the accounting and tax bases of assets, liabilities, unused tax losses and unused tax credits, using substantively enacted income tax rates. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in net income in the year in which the change occurs. Deferred tax assets are only recognized to the extent it is probable that sufficient future taxable income will be available to allow the deferred tax asset to be realized.

The Company records foreign exchange gains and losses representing the impacts of movements in foreign exchange rates on the tax bases of non-monetary assets and liabilities which are denominated in foreign currencies. Foreign exchange gains and losses relating to deferred income taxes are included under income tax in the consolidated statements of operations and comprehensive income.

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CashCash comprises of cash on hand and deposits held with banks. Bank overdrafts that are repayable on demand and form an integral part of the Company’s cash management, whereby management has the ability and intent to net bank overdrafts against cash, are included as a component of cash for the purpose of the consolidated statements of cash flows.

Restricted cashSome cash balances are restricted under the terms of the Company’s debt facility with BNP Paribas. The restricted cash represents proceeds from borrowing base assets. Cash may be disbursed from the restricted accounts for approved purposes as designated by the credit agreement.

Inventories and supplies

Crude Oil InventoryCrude oil inventory consists of crude oil in storage at the statement of financial position date and is valued at the lower of cost, using the weighted average cost method, or net realizable value. Costs include direct and indirect expenses incurred in bringing the crude oil to its existing condition and location.

Marine Fuel InventoryMarine fuel inventory consists of marine fuel in storage at the statement of financial position date and is valued at the lower of cost, using the weighted average cost method, or net realizable value. Costs include direct and indirect expenses incurred in bringing the marine fuel to its existing location.

Financial instruments and hedging activitiesAll financial assets and liabilities are recognized on the consolidated statements of financial position initially at fair value when we become a party to the contractual provisions of the instrument. Subsequent measurement of the financial instruments is based on their classification. We classify each financial instrument into one of the following categories: loans or receivables, fair value through profit or loss and other financial liabilities. The classification depends on the characteristics and the purpose for which the financial instruments were acquired. Except in limited circumstances, the classification of financial instruments is not subsequently changed.

Financial instruments classified as fair value through profit or loss (FVTPL) on the Company’s consolidated statements of financial position includes cash, restricted cash and derivatives. Realized and unrealized gains and losses from financial assets and liabilities carried at FTVPL are recognized in net income in the years such gains and losses arise. Transaction costs related to these financial assets and liabilities are included in net income when incurred.

Financial instruments carried at amortized cost include the Company’s accounts receivable, accounts payable and accrued liabilities, current-portion and non-current portion of long-term debt, amounts due to shareholder and obligations under finance leases. Transaction costs relating to long-term debt are included within fair value and amortized using the using the effective interest rate method. Gains and losses on financial assets and liabilities carried at cost or amortized cost is recognized in net income when these assets or liabilities settle.

DerivativesCoastal uses puts and call option contracts to manage commodity price risk as required as part of the debt facility with BNP Paribas. The facility also requires interest rate swap contracts to be utilized. The Company records these instruments at fair value at each statement of financial position date and changes in fair value are included in other income during the year of change.

Hedge accountingThe Company has not adopted hedge accounting.

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Provisions and ContingenciesProvisions are recognized when we have a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where appropriate, the future cash flow estimates are adjusted to reflect the risks specific to the liability.

If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money. Where discounting is used, the accretion of the provision due to the passage of time is recognized within finance expense.

Contingent liabilities are possible obligations which will be confirmed by future events that are not necessarily within our control, or are present obligations where the obligation cannot be measured reliably or it is not probable that settlement will be required. Contingent liabilities are disclosed only if the possibility of settlement is greater than remote probability. Contingent liabilities are not recorded in the consolidated financial statements.

LeasesThe Company classifies leases entered into as either finance or operating leases. Leases that transfer substantially all of the risks and benefits of ownership are capitalized as finance leases within PP&E and other liabilities. All other leases are recorded as operating leases and expensed as incurred within operating expenses.

WarrantsWarrants have an exercise price denominated in Canadian dollars while the Company’s functional currency is U.S. dollars. As the number of common shares to be issued upon exercise of the warrants is variable, the warrants must be classified as a financial liability at fair value through profit or loss. Accordingly, they are measured at fair value each balance sheet date using the Black-Scholes option pricing model with changes in fair value (including the foreign exchange impact) recognized as a gain or loss.

Share capitalCommon shares are classified as equity. Incremental costs directly attributable to the issue of common shares are recognized as a deduction from equity, net of any tax effects.

Changes in accounting policiesThe Company has reviewed new and revised accounting pronouncements that have been issued but are not yet effective and determined that the following may have an impact on the Company:

In November 2009, the IASB issued IFRS 9, “Financial Instruments,” which is the result of the first phase of the IASB’s project to replace IAS 39, “Financial Instruments: Recognition and Measurement.” In October 2010, the standard was revised. The new and revised standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. The standard is required to be adopted for periods beginning January 1, 2015. The adoption of this standard should not have a material impact on the Company’s consolidated financial statements.

In May 2011, the IASB issued IFRS 10, “Consolidated Financial Statements,” which provides additional guidance to determine whether an investee should be consolidated. The guidance applies to all investees, including special purpose entities. The standard is required to be adopted for periods beginning January 1, 2013. We are evaluating the impact that this standard may have on our consolidated financial statements.

In May 2011, the IASB issued IFRS 11, “Joint Arrangements,” which presents a new model for determining whether an entity should account for joint arrangements using proportionate consolidation or the equity method. An entity will have to follow the substance rather than legal form of a joint arrangement and will no longer have a choice of accounting method. The standard is required to be adopted for periods beginning January 1, 2013. We are evaluating the impact that this standard may have on our consolidated financial statements.

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In May 2011, the IASB issued IFRS 12, “Disclosure of Interests in Other Entities,” which aggregates and amends disclosure requirements included within other standards. The standard requires a company to provide disclosures about subsidiaries, joint arrangements, associates and unconsolidated structured entities. We are evaluating the impact that this standard may have on our consolidated financial statements.

In May 2011, the IASB issued IFRS 13, “Fair Value Measurement,” to provide comprehensive guidance for instances where IFRS requires fair value to be used. The standard provides guidance on determining fair value and requires disclosures about those measurements. The standard is required to be adopted for periods beginning January 1, 2013. We are evaluating the impact that this standard may have on our consolidated financial statements.

In May 2011, the IASB issued amendments to IAS 27, “Separate Financial Statements,” to establish the accounting and disclosure requirements for investments in subsidiaries, joint ventures and associates when an entity prepares separate financial statements and replaces the current IAS 27, “Consolidated and Separate Financial Statements,” as the consolidation guidance is included in IFRS 10, “Consolidated Financial Statements.” The standard is required to be adopted for periods beginning on or after January 1, 2013. The adoption of this standard will not have a material impact on the Company’s consolidated financial statements.

In May 2011, the IASB issued amendments to IAS 28, “Investments in Associates and Joint Ventures,” to establish the accounting for investments in associates and defines how the equity method is applied when accounting for associates and joint ventures. The standard is required to be adopted for periods beginning on or after January 1, 2013. We are evaluating the impact that this standard may have on our consolidated financial statements.

In June 2011, the IASB issued amendments to IAS 1, “Presentation of Items of Other Comprehensive Income,” to split items of other comprehensive income (OCI) between those that are reclassed to income and those that are not. The standard is required to be adopted for periods beginning on or after July 1, 2012. We are evaluating the impact that this standard may have on our statements of operations and financial position.

On June 16, 2011, the IASB issued amendments to IAS 19, “Employee Benefits.” The amendments will improve the recognition and disclosure requirements for defined benefit plans. The new requirements are effective for annual periods beginning on or after January 1, 2013, with earlier application permitted. This amendment will not impact our consolidated financial statements.

In December 2011, the IASB issued final amendments to IFRS 7, “Financial Instruments: Disclosures,” relating to the requirements for the offsetting of a financial asset and financial liabilities when offsetting is permitted under IFRS. The disclosure amendments are required to be adopted retrospectively for periods beginning January 1, 2013. We are evaluating the impact that this standard may have on our consolidated financial statements.

In December 2011, the IASB issued amendments to IAS 32, “Financial Instruments: Presentation,” to address inconsistencies when applying the offsetting criteria outlined in this standard. These amendments clarify certain of the criteria required to be met in order to permit the offsetting of financial assets and financial liabilities. The standard is required to be adopted retrospectively for periods beginning January 1, 2014. We are evaluating the impact that this standard may have on our consolidated financial statements.

Note 4. Restricted cashThe Company has cash balances which are restricted by the Company’s banking institutions. The following table summarizes the restricted cash balances:

As at December 31, December 31,

2012 2011Collateral in support of corporate letter of credit (Note 20) $1,458 $1,400Restricted in support of long-term debt 4,994 27,047

$6,452 $28,447

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The terms of the debt facility with BNP Paribas, Commonwealth Bank of Australia, Standard Bank and Standard Chartered bank (“the lenders”) requires that the Company maintain balances in restricted accounts equal to 50% of its projected debt service over the next six months.

Note 5. Accounts receivable


2012 2011Oil sales $34,854 $-Receivable under risk service contract 4,099 - Refundable taxes (VAT) 16,888 16,115Other 1,007 824

$56,848 $16,939

Note 6. Inventories


2012 2011Marine fuel $5,245 $2,857 Crude oil inventory 15,611 11,304

$20,856 $14,161

The crude oil inventory balance includes $15.61 million of inventory (December 31, 2011: $11.30 million) which is pledged as security under the debt arrangement with BNP Paribas.

The amount of inventory expensed, including the depletion component, in 2012 was $205.49 million (2011: $145.70 million).

Note 7. Exploration and evaluation assets

Exploration and Evaluation

cost and Net book Value as at December 31, 2010 $31,068Additions 145,363 Transfers to property, plant and equipment (136,176)Exploration expense (8,374)

as at December 31, 2011 31,881 Additions 99,170 Exploration expense (7,477)

as at December 31, 2012 $123,574

Exploration and evaluation assets (“E&E assets”) mainly comprise property, geological survey and capitalized exploration drilling costs in respect of non-commercially assessed fields within our G5/43 concession. Management considers the E&E assets to be of an intangible nature.

During the year ended December 31, 2012, $7.04 million of costs associated with decommissioning liabilities are included within additions (year ended December 31, 2011: $nil million).

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During the year ended December 31, 2012, the Company expensed $7.48 million largely in relation to non-commercial results at Songkhla J (2011: $6.83 million was expensed in relation to non-commercial results at Benjarong and relinquishment of some acreage of the G5/50 block).

Note 8. Property, plant and equipment

Assets Under Construction

Oil & Gas Properties

Corporate and Other Total

cost

as at December 31, 2010 $10,706 $276,488 $1,584 $288,778 Additions - 32,001 1,134 33,135 Disposals (10,706) (1,427) - (12,133)Transfers from exploration and evaluation assets - 136,176 - 136,176

as at December 31, 2011 - 443,238 2,718 445,956 Additions 50,576 220,992 1,156 272,724 Assets brought into use (28,828) 28,828 - Disposals (300) - - (300)

as at December 31, 2012 $21,448 $693,058 $3,874 $718,380

accumulated depletion, depreciation and impairment

as at December 31, 2010 10,706 30,911 913 42,530 Depletion and depreciation - 59,447 351 59,798 Disposals (10,706) (718) - (11,424)

as at December 31, 2011 - 89,640 1,264 90,904 Depletion and depreciation - 71,539 668 72,207

as at December 31, 2012 $- $161,179 $1,932 $163,111

carrying amount

as at December 31, 2010 $- $245,577 $671 $246,248 as at December 31, 2011 $- $353,598 $1,454 $355,052 as at December 31, 2012 $21,448 $531,879 $1,942 $555,269

Included within Oil & Gas Properties carrying amount at December 31, 2010, are assets held under finance leases, which have a carrying amount of $0.95 million. The depreciation charged on these assets amounted to $nil (2011: $0.24 million). The Company terminated these finance leases during Q3 2011 (Note 14).

During the year ended December 31, 2012, $3.36 million of costs associated with decommissioning liabilities are included within additions offset by a credit for a change in estimates of $6.56 million for a net credit of $ $3.20 million (year ended December 31, 2011: $24.96 million charge).

Depletion and depreciation expense recognized in property, plant and equipment for the year ended December 31, 2012 was $72.21 million (2011: $59.80 million), whereas the charge for depletion and depreciation expense recognized in the consolidated statements of operations was $70.14 million (2011: $16.14 million). The difference relates to an inventory adjustment for crude oil produced but not yet sold.

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Note 9. Investment in and advances to Apico LLCThe Company has a 39% (2011: 36.1%) interest in Apico LLC (“Apico”), a limited liability company incorporated in the State of Delaware, USA. Apico’s primary purpose is the acquisition, exploration and development of onshore petroleum interests in the Kingdom of Thailand. Apico has the following working interests in petroleum concessions located in the Khorat Plateau area in northeastern Thailand:

Petroleum Concessionapico’s interest Net to coastal

2012 & 2011 2012 2011Block EU-1 and E-5N in the Sinphuhorm gas field 35% 13.648% 12.635%Block L15/43 - surrounding the Sinphuhorm gas field 100% 38.994% 36.100%Block L27/43 – southeast of the Sinphuhorm gas field 100% 38.994% 36.100%

The Company’s investment in Apico exceeds its proportionate share of net assets of Apico (“excess basis”). This difference has been allocated to Apico’s oil and gas properties and is being amortized using the units of production method. At December 31, 2012, the remaining unamortized excess basis was $19.43 million (December 31, 2011: $12.89 million).

The following table summarizes the Company’s investments in and advances to Apico:

As atDecember

31, 2012December

31, 2011Balance, beginning of year $47,698 $47,261Acquisition of additional ownership interest 9,250 -Advances during the year - 1,446Share of earnings, net of taxes 19,759 15,583Amortization of excess basis in Apico (649) (1,056)Earnings distributions (15,792) (15,536)Balance, end of year $60,266 $47,698

The following table summarizes Apico LLC’s assets and liabilities:

As atDecember

31, 2012December

31, 2011Current assets 34,693 $19,419Non-current assets 118,166 109,733Current liabilities 45,387 30,694Non-current liabilities 2,306 2,731

The following table summarizes Apico LLC’s revenue and net income:

Years ended December 31, 2012 2011Revenue $98,256 $86,625 Expenses 15,692 17,166 Income taxes 32,801 26,326 Net income 49,763 43,133

The Company’s share of Apico’s commitments relating to geological studies, seismic surveys and exploratory drilling for the next 1 year is $1.37 million. There is also a bank guarantee of $0.26 million to cover customs duties.

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Note 10. Accounts payable and accrued liabilities


2012 2011Trade payables $72,770 $34,252 Accrued payables 56,601 23,084 Other 1,634 2,056

$131,005 $59,392

Included in accrued payables is an accrual of $4.24 million for the fair value of vested stock appreciation rights (SARs) (December 31, 2011: $6.17 million). The Company incurred a liability of $9.52 million for the year ended December 31, 2012 (2011: $15.34 million). Of this, $1.19 million for the year ended December 31, 2012, (2011: $1.51 million) was capitalized to property, plant and equipment.

The fair value of these instruments was determined using the Black-Scholes model based on observable market prices. The full fair value of granted SARs units at December 31, 2012, is $10.45 million (December 31, 2011: $13.17 million).

In 2012 the Company awarded stock appreciation rights for the equivalent of approximately 168,691 (2011: 327,660) common shares, none of which (2010: nil) are contingent upon the achievement of certain market-based performance goals established by the Company. These awards vest and are cash-settled 33.3% on each of the subsequent anniversaries of the grant date.

Note 11. Derivative liability - WarrantsThe warrants outstanding at the beginning of the year are exercisable at Cdn $1.136 per share equivalent and expire January 23, 2014. During 2012, no warrants were exercised (2011: 340,000 warrants exercised in exchange for 286,082 common shares). The changes in warrants were as follows:


Numberof warrants

weighted averageexercise price

Numberof warrants

Weighted averageexercise price

Balance, beginning of period 200,000 $1.11 540,000 $1.13Warrants issued - - - -Warrants exercised - - (340,000) 1.13Warrants expired - - -Balance, end of period 200,000 $1.13 200,000 $1.11

The recorded values of the aforementioned warrants were calculated using the Black-Scholes pricing model over the remaining term of the warrants. The key inputs are as follows:


2012 2011Risk free interest rate as per US Treasury Bonds 0.16% 0.25%Share price (Canadian dollars) $19.96 $14.07Remaining term of the warrants 1.08 years 2.08 yearsVolatility 40% 40%

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Note 12. Long term debt


2012 2011Revolving debt facility $200,000 $80,000 Unused portion of debt facility (100,000) - Total debt drawn down 100,000 80,000 Unamortised debt issue costs (4,934) (2,191)Carrying value of long-term debt 95,066 77,809 Current portion of long-term debt - (55,653)Non-Current portion of long-term debt $95,066 $22,156

Current portion of long-term debt shown on the consolidated statements of financial position comprises:

As atDecember 31, December 31,

2012 2011Principal $- $55,653 Interest 34 9

$34 $55,662

Debt facilityThe facility is a borrowing base facility secured by certain of the Company’s petroleum assets as designated during each semiannual redetermination period. The facility is secured by pledges of the Company’s interest in the borrowing base assets and associated facilities, pledges of the bank accounts into which revenue from the borrowing base assets is received, a floating charge over certain of the Company’s other assets and a general security assignment consistent with standard project finance arrangements. The terms of the agreement require cash to be placed in restricted accounts, as described in Note 4.

In Q2 2012 the Company amended the terms of the revolving debt facility with BNP Paribas and Commonwealth Bank of Australia. This saw the facility increase from $80.0 million to $100.0 million, an extension of the amortization period of the borrowing base, and a significant lessening of the terms required to utilize cash balances held with the lender. In Q3 2012 the facility was further upsized from $100.0 million to $200.0 million. Additionally, Standard Bank and Standard Chartered Bank joined the syndicate. The facility amount begins amortizing on 30 June 2014 at the rate of $40 million every six months through to the earlier of June 30, 2016, or the reserve tail date (defined as the date at which less than 25% of the Company’s current 1P reserve base remains).

The effective interest rate for the year ended December 31, 2012, was 6.62% (2011: 5.14%) per annum.

As a requirement of the facility, the Company is required to enter into derivative contracts on a percentage of its projected crude oil production over a rolling 18 to 24 month period. The following is a summary of the crude oil derivative contracts outstanding at December 31, 2012:

Notional Volumes Term

Average Strike Price

Fair value ofasset (liability)

long PutsBrent 1,360,801 Jan. 2013 – Apr. 2014 $70.00/bbl $766

short callsBrent 1,360,801 Jan. 2013 – Apr. 2014 $125.19/bbl (2,372)

collarBrent 190,167 Jan. 2013 – Apr. 2014 - (267)

Fair value of derivative assets (liabilities) ($1,873)

The collar has a floor of $70 and a cap of $127.

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The following is a summary of the crude oil derivative contracts outstanding at December 31, 2011:

Notional Volumes Term

Average Strike Price

Fair value ofasset (liability)

long PutsBrent 1,413,500 Jan. 2012 – Apr. 2013 $74.24/bbl $2,778

short callsBrent 1,246,500 Jan. 2012 – Apr. 2013 $103.12/bbl (18,609)

Fair value of derivative assets (liabilities) $(15,831)

The split between the current and non-current portions of these contracts:

December 31,2012

December 31,2011

Current portion ($1,372) ($14,557)Non-current portion (502) (1,274)Total fair value of net derivative liabilities ($1,874) ($15,831)

In 2012 the Company entered into a contract to swap 50% of its expected LIBOR interest rate exposure from floating to fixed over a 30 month period commencing July 30, 2012, at 0.98% per annum. This was followed by a further contract where the Company entered into a contract to swap 50% of its expected LIBOR interest rate exposure from floating to fixed over a 30 month period commencing July 30, 2012, at 0.98% per annum.

The carrying value of these financial derivative assets is $0.13 million as of December 31, 2012, (December 31, 2011: $0.06 million derivative asset).

Realized and unrealized gains and losses on the crude oil derivative contracts and the interest rate swaps are summarized in the following table:

Years ended December 31, 2012 2011Realized loss on crude oil derivative contracts (16,407) $(19,995)Realized loss on interest rate swap (92) (32)Unrealized gains on crude oil derivative contracts 13,957 919Unrealized gain (loss) on interest rate swap 73 (76)

($2,469) $(19,184)

Changes in fair values associated with derivative contracts are included within other income in the consolidated statements of operations and comprehensive income.

All derivative contracts are considered as held-for-trading using the criteria specified under IFRS.

Note 13. Decommissioning liabilities Changes in the carrying amount of decommissioning liabilities are as follows:

Years ended December 31, 2012 2011Decommissioning liabilities, Beginning of Period $42,124 $17,655

Obligations incurred with development activities 10,392 17,475 Changes in estimates (6,562) 7,488 Obligations settled - (964)Unwinding of discount 772 470

Decommissioning liabilities, End of Period $46,726 $42,124

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Decommissioning liabilities represents the present value of estimated remediation and reclamation costs associated with our PP&E. Coastal has discounted the estimated asset retirement obligation using a risk-free rate of 2.4% (December 31, 2011: 1.8%). While the provision for abandonment is based on management’s best estimates of future costs and the economic lives of the assets involved, there is uncertainty regarding both the amount and timing of incurring these costs. Management anticipates the remedial work will occur approximately 12-35 years from the statement of financial position date. The Company expects to fund decommissioning liabilities from future cash flows from our operations. The total undiscounted amount of estimated cash flows required to settle the obligations at December 31, 2012, is $54.46 million (2011: $42.5 million).

Note 14. Leases Obligations under finance leases

During 2011, the Company terminated all of its finance leases. As a result, the Company recorded a gain of $0.62 million as a result of derecognizing the assets and the related finance lease obligations.

The interest arising on those finance leases is disclosed in Note 16.

Operating leasesThe Company incurred $48.42 million of expenses under operating leases for the year ended December 31, 2012, (2011: $35.75 million). The commitments associated with these leases are detailed in Note 20.

Note 15. Finance expense

Years ended December 31, 2012 2011Long-term debt interest expense $3,012 $3,308 Unwinding discount related to decommissioning liabilities (Note 13) 772 470 Finance lease interest - 385 Unrealized loss on derivative liability - warrant (Note 11) 931 662

$4,715 $4,825

Note 16. Other income

Years ended December 31, 2012 2011Change in fair value of derivative contracts (Note 12) ($2,469) ($19,184)Interest 39 6 Foreign exchange losses (2,340) (2,388)

($4,770) ($21,566)

Note 17. Employee benefits

Years ended December 31, 2012 2011Equity-settled share-based payment (Note 19) $6,054 $2,774 Cash-settled share-based payment (Note 10) 9,516 13,670 Termination benefits - 450 Other employee benefits 36,264 23,601 Total employee benefits expense 51,834 40,495 Capitalized employee benefits (8,050) (8,456)Expensed employee benefits $43,784 $32,039

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Note 18. Related parties

Major subsidiaries and Apico LLCThe consolidated financial statements include the financial statements of Coastal and its affiliated subsidiaries as at December 31, 2012, and December 31, 2011. Transactions involving the Company, its subsidiaries and equity investment are eliminated upon consolidation. In the opinion of management there are no related party transactions with entities outside the consolidated group in the year ended December 31, 2012 and 2011, except for those disclosed below.

Compensation of key management personnelKey management personnel include the Chairman, Chief Executive Officer, Chief Financial Officer and the General Manager in Thailand. Compensation paid to and share-based compensation attributable to key management personnel consists of the following:

Years Ended December 31, 2012 2011Short-term benefits $4,295 $3,678 Post-retirment benefits 25 33 Equity-settled share-based payment 4,113 1,740 Cash-settled share-based payment 4,796 8,084

$13,229 $13,535

The compensation of directors and key executives is determined by the compensation committee having regard to the performance of individuals and market trends.

Net profits interestIn 2012, a related party of the primary shareholder, O.S. Wyatt, Jr., reached payout under the terms of a net profits agreement following the recovery of all capital and operating expenditures relating to the G5/43 concession. Under the terms of this arrangement, the Company paid $0.65 million and accrued a further $0.10 million at December 31, 2012. These amounts are based upon 2.5% of net profits from the Gulf of Thailand Block G5/43 operations. The net profits agreement was executed in 2005 and has been previously disclosed by the Company.

Note 19. Equity

Common SharesAuthorized share capital consists of 250,000,000 common shares with a par value of $0.04 each. Each share carries equal voting rights, is non-preferential and participates evenly in the event of a dividend payment or in the winding up of the Company. At December 31, 2012, 113,228,067 common shares were issued and fully paid (December 31, 2011: 113,605,881 shares).

During the year ended December 31, 2012, the Company repurchased 1,295,450 common shares through the facilities of the TSX and other Canadian market places under a normal course issuer bid (“NCIB”) at an average cost of $14.07 per share (Cdn$ 14.48 per share) for a total repurchase cost of $18.22 million. The book value of the common shares repurchased was $1.87 per share for a total book value of $2.42 million that was recorded to share capital. The residual amount of $15.80 million was recorded directly to retained earnings. All of the common shares under the NCIB were cancelled. The NCIB will terminate on the earliest of the purchase of 5,715,972 common shares, Coastal providing a notice of termination, and May 24, 2013. Any common shares purchased pursuant to the NCIB will be cancelled by the Company.

Also in 2012, the Company repurchased 33,395 common shares from directors. The book value of the common shares repurchased was $1.86 per share for a total book value of $0.06 million that was recorded to share capital. The residual amount of $0.47 million was recorded directly to retained earnings. All of the common shares repurchased were cancelled.

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Stock optionsThe Company has a stock option plan (the “Plan”) in compliance with the TSX’s policy for granting stock options. Under the Plan, the number of shares reserved for issuance may not exceed 15,000,000 shares. At December 31, 2012, there remained available for future issuance 5,352,732 stock options, restricted stock units (discussed below) or a combination thereof. The exercise price of each option shall not be less than the market price of the Company’s stock at the date of grant. The vesting term of options under the Plan is determined by the Company’s Board of Directors, but options granted typically vest over a period of three years. Prior to the January 2009 grant, the options vested one-quarter on the date of the grant and one-quarter on each subsequent anniversary of the date of the grant. Beginning with the January 2009 grant, the options vest one-third on each subsequent anniversary of the date of grant. The maximum exercise period of options granted under the Plan is five years following the grant date. The changes in stock options were as follows:


Numberof options

weighted averageexercise price

Numberof options

Weighted averageexercise price

Balance, beginning of year 8,545,717 $5.79 10,794,987 $3.47Options granted - - 1,591,947 $13.58Options exercised (3,234,978) $3.78 (3,602,288) $2.15Options forfeited (14,520) $8.20 (238,929) $4.74

Balance, end of year 5,296,219 $7.16 8,545,717 $5.79

For share options exercised in the years ended December 31, 2012, the weighted average share price at the date of exercise was $18.78 (2011: $8.78).

Of the 3,234,978 ISOs that were exercised during 2012 (2011: 3,602,288), 2,141,359 were cash settled (2011: nil). The cash settlement amounted to $33.86 million (2011: $nil), with $2.20 million (2011: $nil) of accumulated stock option expense being reclassified from contributed surplus to retained earnings. The residual difference of $31.66 million charge was recorded in retained earnings.

The following table summarizes the outstanding and exercisable options at December 31, 2012:

Grant Date

Number Outstanding

Remaining Contractual Life

Exercise Price

Expiry Date

Number Exercisable

Sep. 16, 2008 100,000 0.75 years $2.31 (Cdn$2.28) Sep. 16, 2013 100,000Jan. 02, 2009 760,917 1.00 years $1.37 (Cdn$1.36) Jan. 01, 2014 739,583Dec. 01, 2009 1,675,661 2.00 years $5.22 (Cdn$5.16) Nov. 30, 2014 1,675,661Dec. 28, 2010 1,326,928 3.00 years $5.85 (Cdn$5.78) Dec. 27, 2015 829,278Dec. 14, 2011 1,432,713 4.00 years $14.27 (Cdn$14.11) Dec. 13, 2016 407,662

5,296,219 3,752,184

The above options are dilutive in 2012 and 2011 and, therefore, have been taken into account in the per share calculations for that year.

The fair value of each option granted is estimated at the time of the grant using the Black-Scholes option pricing model. The weighted average assumptions for grants and the weighted average fair value of option awards granted in 2011 were as follows:

2011Risk-free interest rate 0.93%Expected life 3 yearsAnnualized volatility 40%Dividend rate 0%Weighted average grant date fair value per option $3.43

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Annualized volatility was determined based upon historic movements in the Company’s share price.

For the year ended December 31, 2012, the Company recorded stock option expenses of $4.21 million (2011: $2.72 million), of which $0.25 million (2011: $0.24million) was capitalized.

Restricted stockThe Company has a restricted stock pan (the “RS Plan”) in compliance with the TSX’s policy for granting restricted stock units (“RSUs”). Under the RS Plan, the number of shares reserved for issuance may, along with other stock plans, not exceed 10% of the total issued and outstanding shares of the Company. At December 31, 2012, there remained available for future issuance 5,352,732 RSUs, stock options or a combination thereof. The vesting term of RSUs under the RS Plan is determined by the Company’s Board of Directors. For the RSUs granted on December 14, 2011, one-third vest on each subsequent anniversary of the date of the grant. The changes in the number of RSUs in 2012 and 2011 were as follows:

2012 2011Balance, beginning of period 205,628 -

RSUs granted 509,963 205,628RSUs settled (41,735) -RSUs forfeited - -

Balance, end of period 673,856 205,628

The following table summarizes the outstanding RSUs at December 31, 2012:

Grant Date

Number Outstanding

Remaining Contractual Life

Grant Date Fair Value

Expiry Date

Dec. 14, 2011 163,893 2 years $12.93 Dec. 14, 2014Dec. 14, 2012 509,963 3 years $19.87 Dec. 14, 2015

673,856

The above RSUs are dilutive both in 2012 and 2011 and, therefore, have been taken into account in the per share calculations detailed below.

The fair value of each RSU granted is estimated at the time of the grant using the Black-Scholes pricing model. The grant date fair value for the RSU’s granted in 2012 is $19.87 per unit (2011: $12.93). The assumptions used in valuing the RSUs are as follows:

2012 2011Risk-free interest rate 0.34% 0.93%Expected life 3 years 3 yearsAnnualized volatility 40% 40%Dividend rate 0% 0%

For the year ended December 31, 2012, the Company recorded RSU expenses of $1.85 million (2011: $0.07 million), of which $0.02 million (2011: $0.01 million) was capitalized.

2012 was the first year RSUs were settled. All RSUs were settled in cash. The cash settlement amounted to $0.66 million, with $0.43 million of accumulated IFRS 2 expense being moved from contributed surplus to retained earnings. The residual difference was recorded in retained earnings.

Contributed surplusThis reserve is being used on an ongoing basis to record stock option expense.

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Net income per shareThe following table summarizes the weighted average number of common shares used in calculating basic and diluted earnings per share. No adjustments to income were required.

Years ended December 31, 2012 2011Weighted average common shares outstanding, basic 113,534,501 112,226,944Effect of stock options and warrants 3,167,440 3,767,396Weighted average common shares outstanding, diluted 116,701,941 115,994,340

The average market price used in the ‘effect of stock options and warrants’ line in the above table was Cdn$16.99 for the year ended December 31, 2012 (2011: Cdn$9.00). Upon translation to US dollars this equates to $17.08 for the year ended December 31, 2012 (2011: $8.85).

Note 20. Commitments and contingencies

Commitments and contingencies

Year

Drilling & Production

Thailand

Drilling & Production

Malaysia G5/50 Other Total2013 $100,400 $137,013 $5,300 $325 $243,0382014 - 125,580 - 132 125,712Thereafter - 52,873 - - 52,873

Note: The column titled ‘Drilling & Production Malaysia’ includes obligations of the 30% non-controlling interest in Coastal Energy KBM Sdn. Bhd.

ThailandThe Company has provided a letter of credit to the Thailand Customs Department for $1.46 million (December 31, 2011: $1.40 million). This letter of credit is cash collateralized, has not been drawn on and remains outstanding as of September 30, 2012.

The Company has entered into various commitments primarily related to the ongoing development of its Thailand G5/43 and G5/50 property concessions, and the Kapal, Banang and Meranti Cluster (“KBM”) service contract in Malaysia (see below). Coastal has secured equipment and work commitments in the Gulf of Thailand and Malaysia. In order to keep both the concessions and service contract, the Company has various development obligations. The Company also has operating lease agreements for office space in Thailand, Malaysia and the United States. The following table summarizes the Company’s outstanding contractual obligations:

The Company’s share of Apico’s commitments is disclosed in Note 7.

Malaysia - Kapal, Banang, Meranti ClusterVia its subsidiary, Coastal Energy KBM Sdn. Bhd (“Coastal Malaysia”), the Company has entered into a Small Field Risk Service Contract (“RSC”) with Petronas for the development and production of petroleum from the KBM cluster of small fields (the “KBM Cluster”) offshore Peninsular Malaysia.

Coastal will be the operator of the KBM Cluster fields and will take a 70% interest in Coastal Malaysia. A third party, Petra Energy, will hold the residual 30%.

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Coastal will provide the upfront development capital, undertaking the development drilling and production of the KBM Cluster. Petronas will remain the owner of the project. Subject to its performance, Coastal will recover its capital and operating expenditures and will be paid a remuneration fee, which will be adjusted by key performance indicators (“KPIs”) based on the timely implementation of the agreed field development plan and budget.

The Company from time to time is involved in various claims, legal proceedings, complaints and disputes with governmental authorities and other stakeholders arising in the ordinary course of business. The Company does not believe that adverse decisions in any pending or threatened proceedings related to any matter, or any amount which it may be required to pay by reason thereof, will have a material effect on the financial condition or future results of operations of the Company.

Note 21. Income taxes

Income TaxesThe Company is required to pay both income taxes and a Special Remuneratory Benefit (“SRB”) in Thailand. Thai income tax is calculated at 50% of taxable income.

SRB is calculated separately for each of the Company’s concessions and is not payable on the concession until all capital expenditures have been recovered from the net cash flows from each concession. The SRB is determined using a sliding scale of rates which range from 0% to 75%, where the rate is principally determined by production volumes and crude oil pricing, subject to certain adjustments such as changes in Thailand’s consumer price index, wholesale price index and cumulative meters drilled on the concession. The calculated SRB rate is applied to petroleum profits for the particular year, as defined in Thai tax legislation, and includes a deduction for all capital spent on the concession.

Income taxes are comprised of the following amounts relating to current tax expense and deferred tax expense:

Years ended December 31, 2012 2011Current income tax expense

Current year 143,275 - Adjustment in respect of prior years 7,054 135 Current income tax expense 150,329 135

Deferred tax expenseOrigination and reversal of temporary differences in the current year 40,464 60,779 Adjustment in respect of prior years (11,808) (2,897)

Deferred tax expense 28,656 57,882 Income tax expense 178,985 58,017

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The provision for income taxes differs from the amount that would have been expected by applying statutory corporate income tax rates to income before taxes. The principal reasons for this difference are as follows:

Years ended December 31, 2012 2011Net income before income taxes $406,933 $106,657 Thailand petroleum income tax statutory rate 50% 50%

Expected income tax expense computed at standard rates 203,467 53,329 Add (deduct) the tax effect of:

Tax differential in other countries (26,413) 2,669 Non-taxable/deductible expenses (23,892) (2,483)Share-based compensation 647 1,384 Special Remuneratory Benefit (“SRB”) tax 36,071 - Unrecognized tax benefits 9,616 (519)Tax basis revaluation (16,028) 4,739 Change in estimates and other (4,754) (1,102)

Income tax expense 178,714 58,017 Consisting of:

Current income tax expense 150,329 135 Deferred tax expense 28,656 57,882

Income tax expense 178,985 58,017

Deferred TaxesThe components of the Company’s deferred tax assets and liabilities arising from temporary differences and loss carryforwards as well as the associated amount of deferred tax recovery or expense recognized in the Company’s consolidated statements of operations and comprehensive income are as follows:

December 31, 2012 December 31, 2011 December 31, 2010

Deferred income tax

(expense) recovery

Deferred tax

(liabilities)assets

Deferred Income Tax

(Expense) Recovery

Deferred Tax(Liabilities)

Assets

DeferredTax

(Liabilities)Assets

PP&E and E&E (10,734) (139,672) (52,104) (128,938) (76,834)Crude oil inventory 12,257 12,257 - - -Deferred derivative losses 15,431 23,347 (459) 7,916 8,375Decommissioning liabilities 2,301 23,363 12,234 21,062 8,828Loss carryforwards (27,818) 100 (19,828) 27,918 47,746Stock-based compensation (1,687) 588 2,275 2,275 -SRB tax (18,406) (18,406) - - -Net deferred tax liability (28,656) (98,423) (57,882) (69,767) (11,885)

As at December 31, 2012, the Company has not recognized $10.10 million (2011: $1.40 million) of deferred tax assets in respect of loss carryforwards in the United States. The equivalent numbers for Mauritius and the United Kingdom are $nil million and $0.05 million (2011: $0.02 million and $0.04 million), respectively. The loss carryforwards in the United States will fully expire by 2032.

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Note 22. Segment reportingIFRS 8 requires operating segments to be identified on the basis of internal reports about components of the Company that are regularly reviewed by the executive officers of the Company to allocate resources to the segments and to assess their performance.

The Company’s reportable and geographical segments are Onshore Thailand, Offshore Thailand, Offshore Malaysia and Other. Other activities include the Company’s corporate offices outside of Thailand and Malaysia. The accounting policies used for the reportable segments are the same as the Company’s accounting policies.

For the purposes of monitoring segment performance and allocating resources between segments, the Company’s executive officers monitor the assets attributable to each segment. All assets are allocated to reportable segments. The following tables show information regarding the Company’s reportable segments.

Segmented income for the year ended December 31, 2012:

Malaysia Offshore

Thailand Onshore

Thailand Offshore


Net oil sales $- $- $667,573 $- $667,573 Reimbursement of expenses under Malaysia risk

service contract 4,099 - - - $4,099 Other Income 31 - (18,637) 13,836 (4,770)

4,130 - 648,936 13,836 666,902

Less: ExpensesProduction - - 149,999 - 149,999 Malaysia risk service contract 4,099 - - - 4,099 Depreciation and depletion - - 66,444 3,695 70,139 Net profits interest - - 1,041 - 1,041 General and administrative 238 - 16,159 23,299 39,696 Exploration - - 7,477 - 7,477 Debt financing fees - - 839 1,326 2,165 Finance expenses - - 772 3,943 4,715

Add: Gains on disposal of property, plant and equipment - - 252 252 Add: Net income from Apico LLC - 19,110 - - 19,110 Net income before taxes ($207) $19,110 $406,205 ($18,175) $406,933

Notes: (1) The offshore Malaysia business did not commence until the third quarter of 2012. (2) All oil sales are made to one customer.

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Segmented income for the year ended December 31, 2011:

Thailand Onshore

Thailand Offshore


Net oil sales $- $318,670 $- $318,670 Other Income - (22,317) 751 (21,566)

- 296,353 751 297,104

Less: ExpensesProduction - 99,263 - 99,263 Depreciation and depletion - 60,956 180 61,136 General and administrative - 7,464 23,989 31,453 Exploration - 8,374 - 8,374 Debt financing fees - 11 785 796 Finance costs - 3,708 1,117 4,825

Add: Net income from Apico LLC 14,527 - - 14,527 Gain on disposal of property, plant and equipment - 623 250 873

Net Income (Loss) before taxes $14,527 $117,200 ($25,070) $106,657

Segmented capital expenditure for the year ended December 31, 2012:

Malaysia Offshore

Thailand Onshore

Thailand Offshore


Capital Expenditures $1,000 $- $365,910 $1,155 $368,065

Segmented capital expenditure for the year ended December 31, 2011:

Thailand Onshore

Thailand Offshore


Capital Expenditures $- $153,392 $143 $153,535

Segmented assets as at December 31, 2012:

Malaysia Offshore

Thailand Onshore

Thailand Offshore


Investment in and advances to Apico LLC $- $60,266 $- $- $60,266 PP&E and E&E carrying amount 1,000 - 531,746 146,097 678,843 Total Assets $11,315 $60,266 $650,001 $172,611 $894,193

Segmented assets as at December 31, 2011:

Thailand Onshore

Thailand Offshore


Investment in and advances to Apico LLC $47,698 $- $- $47,698 PP&E and E&E carrying amount $- 386,492 441 386,933 Total Assets $47,698 $455,748 $15,285 $518,731

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Note 23. Capital managementThe Company manages its capital structure and makes adjustments in response to changes in economic conditions and the risk characteristics of the underlying assets. The Company considers its capital structure to include common share capital, long-term debt and adjusted working capital (a measurement defined as current assets less current liabilities, with current liabilities being as per the number on the face of the consolidated statements of financial position). In order to maintain or adjust the capital structure, from time to time the Company may issue common shares or other securities, incur debt, sell assets or adjust its capital spending to manage current and projected debt levels. The Company may also repurchase common shares when the Company believes the market price does not reflect the underlying values of the common shares.

The Company’s capital structure is comprised as follows:

As at December 31, 2012 December 31, 2011Total equity $430,529 $250,867Derivative liability – Warrants 3,784 2,853Long-term debt drawn 100,000 80,000Working capital deficit (asset) excluding long-term debt drawn (1) 70,350 (9,667)

$604,663 $324,053

Note 1: This amount excludes the current portion of the bank debt and the derivative liability for warrants (which by the definition above would normally be included in this computation) as they are already included above.

As of December 31, 2012, the Company has drawn $100.00 million of its $200.0 million borrowing facility. Management believes it can access the equity and credit markets in the future should circumstances deem raising additional equity or debt is necessary.

The Company is in compliance with the terms of its debt agreement.

Note 24. Financial instruments and financial risk management

Financial risk management objectivesManagement co-ordinates access to financial markets and monitors and manages financial risk. These financial risks include fair value risk, market risks (comprising currency, interest rate, commodity price and credit risk) and liquidity risk.

Management seeks to adopt practicable yet effective approaches in a manner consistent with the current nature and scale of operations. This is manifested in procedures such as seeking to match currency inflows with currency outflows in the same currency, and by avoiding the use of derivative instruments where possible. The Company does not undertake derivative transactions for speculative trading purposes.

Fair valuesThe Company’s financial instruments include cash, restricted cash, derivative assets and liabilities, accounts receivable, and accounts payable and accrued liabilities. Cash, derivative assets, derivative liabilities and the derivative liability for warrants are carried at fair value. The Company considers that almost all other items (excluding long-term debt) have a carrying value that approximates their fair value due to their short-term nature. Long-term debt is carried at amortised cost.

The fair value of the Company’s long-term debt as at December 31, 2012, was $96.11 million (December 2011: $76.70 million) when using the market LIBOR rate.

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The Company classifies the fair value of cash, restricted cash, derivative commodity contracts and the derivative liability for warrants according to the following hierarchy based on the amount of observable inputs used to value the instrument.

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the market place.

Level 3 – Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.

The Company’s cash, restricted cash and derivative commodity contracts have been assessed on the fair value hierarchy described above. Cash and restricted cash are classified as Level 1.

The Company’s derivative commodity contracts are classified as fair value through profit and loss, and their fair values are marked to market every quarter based on inputs from quoted market prices in the futures market on the statement of financial position date. As discussed in Note 12, these derivative instruments are solely required for debt facilities. These contracts as well as the derivative liabilities associated with warrants are classified as Level 2.

The Company considers its risks in relation to financial instruments in the following categories, of which management considers that no category has significantly worsened in 2012 relative to 2011.

Credit riskCredit risk is the risk that a counterparty to a financial instrument will not discharge its obligations, resulting in a financial loss to the Company. The Company has procedures in place to minimize the credit risk it will assume. Coastal personnel evaluate credit risk on an ongoing basis, including an evaluation of counterparty credit rating and counterparty concentrations measured by amount and percentage.

The primary sources of credit risk for the Company arise from the following financial assets: (1) cash and restricted cash; (2) accounts receivable; (3) derivative assets. The Company has not had any credit losses in the past beyond that described below.

At December 31, 2012, the Company had $0.20 million of financial assets that were overdue (2011: $nil). This relates to the sale of surplus equipment. Management continues to work with the counterparty to resolve settlement of this balance. No allowance has been made for doubtful accounts receivable (2011: $nil).

The Company’s accounts receivable and other consists primarily of oil sales followed by Value Added Tax (“VAT”) refunds from the governments of Great Britain and Thailand. The Company’s maximum exposure to credit risk at the statement of financial position date is as follows:

As atDecember 31,

2012December 31,

2011Cash $63,897 $22,995Restricted cash 6,452 28,447Refundable taxes (Thailand) 16,888 16,115Trade receivable 34,854 -Receivable under risk service contract 4,099 -Other accounts receivable 1,007 824Derivative asset 132 59

$127,329 $68,440

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Revenues in both years relate to a single customer that had a credit rating of BBB+ with Standard and Poors as at December 31, 2012. The Company’s trade receivables in at the end of each year were less than 30 days aged and were subsequently fully collected.

Typically, the Company’s maximum credit exposure to customers is revenue from one month’s commodity sales. The Company’s standard credit terms have been (receipt of) payment within 30 days. The Company’s policy to mitigate credit risk associated with commodity sales is to establish relationships with creditworthy customers. The Company has not written off any amounts receivable in either 2012 or 2011.

The Company has pledged security (Note 12) in relation to its long-term debt.

Liquidity riskLiquidity risk is the risk that the Company will not be able to meet its obligations with respect to its financial liabilities. The Company’s financial liabilities are comprised of accounts payable and accrued liabilities, derivative liabilities, long-term debt, obligations under operating leases and future contractual commitments. The Company frequently assesses its liquidity position and obligations under its financial liabilities by preparing financial forecasts. Coastal mitigates liquidity risks by maintaining a sufficient cash balance as well as maintaining a sufficient current and projected liquidity cushion to meet expected future payments.

The Company’s financial liabilities arose primarily from the development of its Thailand properties. Payment terms on the Company’s accounts payable and accrued liabilities are typically 30 to 60 days from receipt of invoice and generally do not bear interest. At December 31, 2012, the Company had recorded all of the obligations associated with its financial liabilities. In the normal course of business, the Company enters into contracts that give rise to commitments for future minimum payments. The following table summarizes the remaining contractual maturities of the Company’s financial liabilities:

December 31, 2012December 31,

2011

within 1 Year

1-2Years 2-5 Years

thereafter total Total

Accounts payable and accrued liabilities $217,757 $- $- $- $217,757 $59,471Long-term debt principal and interest 34 - 40,000 60,000 100,034 80,009Derivative liabilities 1,372 502 - - 1,874 15,831Derivative liability - warrants - 3,784 - - 3,784 2,853

$219,163 $4,286 $40,000 $60,000 $323,449 $158,164

Market riskMarket risk is the risk that the fair value (for assets or liabilities considered to be fair value through profit and loss and available-for-sale) or future cash flows (for assets or liabilities considered to be held-to-maturity, other financial liabilities, and loans or receivables) of a financial instrument will fluctuate because of changes in market prices. The Company evaluates market risk on an ongoing basis. Coastal assesses the impact of variability in identified market risk on its various assets and liabilities and has established policies and procedures to mitigate market risk on its foreign exchange, interest rates and derivative contract.

(a) Currency riskCoastal operates internationally and therefore is exposed to the effects of changes in currency exchange rates. Although the functional currency of the Company is United States Dollars, it also transacts business in Thai Baht, Malaysian Ringgit, Singapore Dollars, Australian Dollars, British Pounds, Canadian Dollars and Euros. The Company is subject to inflation in the countries in which it operates and fluctuations in the rate of currency exchange between the United States and these other countries. The Company does not currently use financial instruments or derivatives to hedge these currency risks.

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Exchange rate fluctuations may affect the costs that the Company incurs in its operations. The Company’s costs are incurred principally in Thai Baht, Malaysian Ringgit, Singapore Dollars, Australian Dollars, British Pounds and Canadian Dollars. The appreciation of non-US Dollar currencies against the US Dollar can increase the costs of operations and capital expenditures in US Dollar terms.

Based on the Company’s net foreign currency exposures at December 31, 2012, a 10% depreciation or appreciation of the foreign currencies against the US Dollar would result in a $1.23 million (December 31, 2011: $0.90 million) increase or decrease in the Company’s after-tax earnings with the same impact on comprehensive income. These exposures are attributable to year-end payables and receivables denominated in currencies other than the US Dollar.

(b) Interest rate riskThe Company is exposed to interest rate risk on its outstanding borrowings and short-term investments. Presently the Company’s credit facility has an interest rate of LIBOR plus 350 bps. The Company monitors its exposure to interest rates and is comfortable with its exposures, given the relatively short-term of the interest rates on long-term debt. The terms of the Company’s long-term debt obligation are described in Note 12. The Company accounts for its borrowings under the long-term debt on an amortized cost basis. The Company had borrowings totaling $100.0 million at December 31, 2012 (December 31, 2011: $80.0 million). A 100 basis point change in interest rates at the statement of financial position date would result in a $1.0 million change in the Company’s annual net income (2011: $0.8 million). The Company has entered into an interest rate swap to specifically manage interest rate risk. Further details can be found in Note 12.

The Company paid an average of 6.62% on its borrowings for the year ended December 31, 2012 (2011: 5.14%).

The Company earned an average of 0.02% on its short-term investments for the year ended December 31, 2012 (2011: 0.05%).

(c) Commodity price riskProfitability of the Company depends on market prices for petroleum and natural gas. Petroleum and natural gas prices are affected by numerous factors such as global consumption and demand for petroleum and natural gas, international economic and political trends, fluctuation in the US Dollar and other currencies, interest rates and inflation.

A 10% decline in the reference price projection would not reduce the availability under the borrowing base at December 31, 2012.

As a requirement of the debt facilities, the Company entered into a derivative hedging agreement described in Note 12. A 10% increase in prices of Brent as of December 31, 2012, would cause an increase in the derivative liability of $2.30 million (2011: increase in liability of $7.31 million) from what is recorded on the statement of financial position. A 10% decrease in prices as of December 31, 2012, would cause a decrease in the liability of $2.40 million (2011: decrease of $5.09 million).

(d) Other price riskThe Company is exposed to equity price risk in relation to stock appreciation rights granted to employees. For more detail, see Note 10.

Note 25. Subsequent eventsThe Company has not had any subsequent events.

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NON-INDEPENDENT DIRECTOR

Randy L. Bartley, President and CEO

William C. Phelps, Chief Financial Officer

Andrew L. Cochran, Executive Director

INDEPENDENT DIRECTORS

C. Robert Black (1) (2) (4)

Former Senior Vice President, Office of the Chairman Texaco, Inc.

Olivier de Montal (2) (3) Administrator, Loze &Associés

Lloyd Barnaby Smith (3) (4) Former British Ambassador to Thailand

John B. Zaozirny (1) (3) Vice Chairman, Canaccord Genuity Corp.

Committees of the Board: (1) Audit, (2) Compensation, (3) Corporate Governance and Nominating, and (4) Reserves

SENIOR MANAGEMENT

Randy L. Bartley, President, CEO, Director

William C. Phelps, Chief Financial Officer, Director

Andrew L. Cochran, Executive Director

John M. Griffith, Vice President, Operations Thailand General Manager

TRADING SYMBOLS

CEN on TSX

CEO on AIM

WEBSITE

www.CoastalEnergy.com

INVESTOR RELATIONS

Matthew E. Laterza T: +01 (713) 877-6793 F: +01 (713) 877-7144 Email: [email protected]

ABBREVIATIONS

bbl Barrelboe barrel of oil equivalent of natural gas and crude oil

on the basis of 1 boe for 6 mcf of natural gasbbl/d barrels of oil per daymbbls thousand barrelsmcf thousand cubic feetmmcf million cubic feetmcf/d thousand cubic feet per daymmcf/d million cubic feet per daybcf billion cubic feet TSX Toronto Stock Exchange (Canada)AIM London AIM Stock Exchange (UK)

THIRD PARTY ADVISORS

Petroleum and Geological Engineers: RPS Group, Ltd.

Auditors: Deloitte LLP (Canada)

Legal Counselors: Stikeman Elliott LLP (Canada & UK) Walkers SPV Limited (Cayman Islands) Chandler & Thong-Ek (Thailand)

Stock Registrars: Computershare (TSX) Capita Registrars (LSE-AIM)

Nominated Advisor (NOMAD): Strand Hanson Limited

COASTAL ENERGY COMPANY

Walkers House 87 Mary Street George Town, Grand Cayman, KY1-9001 Cayman Islands, BWI

Level 39 Unit 3901-3904 Exchange Tower Building 338 Sukhumvit Road, Klongtoey Bangkok 10110 Thailand

41st Floor, Vista Tower, The Intermark 348 Jalan Tun Razak 50400 Kuala Lumpur, Malaysia

3355 West Alabama, Suite 500 Houston, Texas 77098-1717 USA T: +01 713 877 7125 F: +01 713 877 7128

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Cayman IslandsWalker House87 Mary StreetPO Box 908GTGeorge Town Grand CaymansKY1-9001

Malaysia COASTAL ENERGY KBM Sdn BhdLevel 23Etiqa Tower 2Jalan Pinang50450 Kuala LumpurMalaysia

uSa3355 West Alabama, Suite 500Houston TX 77098+1 (713) 877-7125

united KingdomCoastal Energy (UK) Company Limited10 Cavalry Square, London, SW3 4RB

thailand24th Floor, Unit 24012405 Two Pacific Place Bldg.142 Sukhumvit RoadKlongtoey, Bangkok 10110+66 (0) 2610 0555

New DirectioN s New Opportunities

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