coastal energy company form 51-101f1 … dated march 27, 2012 relating to its evaluation of the...
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COASTAL ENERGY COMPANY
FORM 51-101F1 STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
Effective Date: December 31, 2011 The crude oil and natural gas properties of Coastal Energy Company (“Coastal” or the “Company”), all of which are located in Thailand, have been evaluated by the independent international petroleum engineering and geological firm, RPS Energy. (“RPS”). The following summary is based on RPS’s report dated March 27, 2012 relating to its evaluation of the Company’s reserves as o f December 31, 2011 (the “Reserves Report ”) and has been prepared in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Assumptions and qualifications relating to costs, prices for future production, and other matters are included below. The Reserves Report is based on data supplied by the Company and on RPS’s opinions of reasonable practice in the industry. All evaluations of future net revenue set forth below are after the deduction of future income tax expenses (unless otherwise noted in the tables), royalties, development costs, production costs, and well abandonment costs, but before consideration of indirect costs such as administrative, overhead, and other miscellaneous expenses. The estimated future net revenue contained in the following tables does not necessarily represent the fair market value of Coastal’s Reserves. There is no assurance that the forecast price and cost assumptions contained in the Reserves Report will be attained and variances could be material. Other assumptions and qualifications relating to costs and other matters are summarized in the notes to the following tables. The recovery and Reserves estimates on Coastal’s properties described herein are estimates only. The actual Reserves on Coastal’s properties may be greater or less than those calculated and these variances may be material. Coastal has no heavy oil Reserves and “crude oil” refers to light and medium crude oil only. Date of Statement of Reserves
This statement is dated March 28, 2012. The information being provided in this statement has been taken from the Reserves Report which was dated March 27, 2012 with an effective date of December 31, 2011. Currency Unless otherwise noted, all dollar amounts contained herein are expressed in United States dollars. Forward-Looking Information
This document contains forward-looking information and statements. These statements relate to future events or the Company’s future performance. All information and statements other than statements of historical fact contained in this document are forward-looking information and statements. Such statements and information may be identified by looking for words such as “approximately”, “can”, “may”, “expect”, “will”, “intend”, “plan”, “predict”, “potential”, “anticipate”, “forecast”, “strategy”, “estimate”, “continue” or similar words or the negative thereof or other comparable terminology. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Forward-looking information and statements are based on the estimates and opinions of RPS, the Company’s management
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and other third parties as at the time that the statements were made. There can be no assurance that the plans, intentions or expectations upon which such forward-looking information and statements are based will occur, and undue reliance should not be placed on any such forward- looking statements.
All information and statements relating to “reserves” are deemed to be forward-looking information and statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and that the reserves can be profitably produced in the future.
In addition to the forward-looking statements identified above, this document contains forward- looking statements pertaining to the following:
oil and natural gas production levels; capital expenditure programs; projections of market prices and costs.
Forward-looking information and statements are subject to risks, uncertainties and assumptions, including those discussed below and elsewhere in this document. Although the Company believes that the expectations represented in such forward-looking information and statements are reasonable, there can be no assurance that such expectations will prove to be correct. Some of the risks which could affect future results and could cause results to differ materially from those expressed in the forward-looking information and statements contained herein include, but are not limited to, the following:
volatility of commodity prices; liabilities inherent in oil and natural gas operations; imprecision of reserve and resource estimates; competition from other industry participants; scarcity of qualified personnel or management or oilfield services; geological, technical, drilling and processing problems; fluctuation in foreign exchange or interest rates; stock market volatility; general economic and industry conditions; environmental risks; inability to access sufficient capital from internal and external sources; and governmental regulation and tax laws.
The forward-looking information and statements contained herein are expressly qualified in their entirety by this cautionary statement. The forward-looking information and statements included in this document are made as of the date specified and we undertake no obligation to publicly update such forward-looking information and statements to reflect new information, subsequent events or otherwise unless required by applicable securities laws.
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Abbreviations
Oil and Natural Gas Liquids Natural Gas
bbl bbls
barrel
barrels
Mcf
MMcf
thousand cubic feet
million cubic feet
bbls/d
barrels per day Mcf/d thousand cubic feet per day
NGLs
natural gas liquids MMcf/d
m
million cubic feet per day
thousand
mm million
Other Abbreviations
barrel a volume equivalent to 158.9874 liters (US 42 gallons) at a temperature of 15.56 degrees centigrade (60 degrees Fahrenheit) and at one atmosphere of pressure
boe barrel of oil equivalent is derived by converting natural gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil ( 6 Mcf: 1bbl)
Btu British thermal unit
cubic feet a volume measuring one foot high by one foot long by one foot deep
mboe 1,000 barrels of oil equivalent
mmboe million barrels of oil equivalent
$MM millions of dollars
scf standard cubic feet
Use of Barrels of Oil Equivalent
Please note that the use of “boe” may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
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Conversions To Convert From
To
Multiply by
Mcf cubic meters 28.174
cubic meters
cubic feet 35.494
bbls
cubic meters 0.159
cubic meters
bbls 6.290
feet
meters 0.305
meters
feet 3.291
Glossary of Technical Terms
The following defined terms have the respective meanings set out below: 1P Proved reserves. 2P Proved reserves + probable reserves. Condensate A mixture of pentanes and heavier hydrocarbons recovered as liquid from
field separators, scubbers or other gathering facilities, or at the inlet of a processing plant before the gas is processed.
Development well A well drilled within the proved area of an oil or gas reservoir to the depth
of a stratigraphic horizon known to be productive. Exploratory well A well drilled to find a new field or to find a new reservoir in a field
previously found to be productive of oil or gas in another reservoir. Hydrocarbons Solid, liquid or gas made up of compounds of carbon and hydrogen in
varying proportions.
Natural Gas Liquids Those hydrocarbon components that can be recovered from natural gas as liquids, including, but not limited to, ethane, propane, butanes, pentanes plus, condensate, and small quantities of non-hydrocarbons.
Royalties A payment to the government or others, usually expressed as a
percentage of total hydrocarbon production.
Definitions
APICO APICO LLC, a United States limited liability company which holds certain working interests in onshore Thailand, and in which the Company holds a 36.1% interest, and its subsidiaries.
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COGE Handbook The “Canadian Oil and Gas Evaluation Handbook” prepared jointly by The Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society) as amended from time to time.
Proved reserves Those reserves that can be estimated with a high degree of certainty to
be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
Probable reserves Those additional reserves that are less certain to be recovered than
proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved + probable reserves.
Reserves The estimated remaining quantities of oil and natural gas and related
substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are further classified according to the level of certainty associated with the estimates and may be subcla ssified based on development and production status.
Reserves Data
A summary of the Company’s reserves by product type based upon forecast price and cost assumptions, before and after applicable royalties, as at December 31, 2011, is presented below.
Summary of Oil and Gas Reserves of the Company Using Forecast Pricing as of December 31, 2011
Light and Medium Crude Oil
Gross Net Natural Gas
Gross Net Natural Gas Liquids Gross Net
TotalsGross Net
Reserve Category (mbbl) (mbbl) (bcf) (bcf) (mbbl) (mbbl) (mboe) (mboe) (mboe)
Proved Reserves: Offshore Developed Producing 25,115 22,910 - - - - 25,115 22,910 Offshore Developed Shut-In 17,171 15,627 17,171 15,627Offshore Developed Nonproducing 467 427 - - - - 467 427Offshore Undeveloped 19,736 17,999 - - - - 19,736 17,999
Total Proved Reserves – 1P 62,489 56,963 - - - - 62,489 56,963Probable Reserves:
Offshore Undeveloped
17,453
15,805 - - - - 17,453 15,805 Total Probable Reserves 17,453 15,805 - - - - 17,453 15,805
Total Proved Plus Probable Reserves – 2P
79,942
72,768
- - - - 79,942
72,768
The tables set forth below summarize the Company’s future net revenue before taxes as at December 31, 2011 based on forecast prices and cost assumptions.
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Net Present Value of Future Net Revenue
Before Income Taxes (MM$), Discounted at
Reserves Category 0% 5% 10% 15% 20%
After Income Taxes (MM$), Discounted at
0% 5% 10% 15% 20%
Unit Value($/bbl) Before Income Tax
Discounted at 10%
Proved Reserves Offshore Developed Producing Offshore Developed Shut-In Offshore Developed Nonproducing Offshore Undeveloped
1903 1436 1140 941 800 1502 1121 886 732 625 $45.39 1341 1060 864 723 618 435 350 297 260 233 $50.32
37 28 23 19 16 9 7 6 5 5 $49.25
1468 1113 882 724 609 475 367 303 260 229 $44.69
Total Proved Reserves – 1P 4749 3637 2909 2407 2043 2421 1845 1492 1257 1092 $46.55Probable Reserves
Offshore Undeveloped $28.99 1489 828 506 333 235 672 326 176 106 69
Total Probable Reserves 1489 828 506 333 235 672 326 176 106 69 $28.99
Total Proved Plus Probable Reserves – 2P
$42.72
6238 4465 3415 2740 2278 3093 2171 1668 1363 1161
Undiscounted total future net revenue for the Company’s offshore properties calculated using forecast prices and costs incorporates the elements presented in the table below.
Future
Net
Future Net Revenue Revenue
Well Before After Reserves Category Revenues Royalties Operating Development Abandonment Income Income Income
(M $) Costs Costs Costs Taxes Taxes Taxes
PROVED
Developed Producing 2,586,990 226,096 333,006 109,834 17,274 1,900,780 931,580 969,200
Developed Non-Producing 47,555 4,156 15,432 3,534 1,065 23,368 11,453 11,915
Developed Shut-In 1,741,738 152,228 194,243 31,061 10,654 1,353,552 663,384 690,168
Undeveloped 2,024,954 176,981 260,915 103,367 12,680 1,471,011 720,950 750,061
Total Proved 6,401,237 559,461 803,596 247,796 41,673 4,748,711 2,327,367 2,421,344
PROBABLE
Total Proved plus Probable 8,368,777 738,525 1,078,264 265,950 47,818 6,238,220 3,145,366 3,092,854
A summary of the Company’s share of APICO’s reserves and future net revenue is presented separately in Appendix “C”.
Future Net Revenue Reserves Category Production Group Before Income Taxes (MM$), (discounted at 10%/year)
Unit Value($/bbl for Liquids)
($/Mcf for Natural Gas) ($/BOE for Total Hydrocarbon)
Proved Reserves Liquids 2,909 Natural Gas 0 Total Hydrocarbon 2,909
51.07 0 51.07
Proved + Probable Reserves Liquids 3,415 Natural Gas 0 Total Hydrocarbon 3,415
46.93 0 46.93
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Pricing Assumptions
Future net revenue in respect of Coastal’s offshore properties calculated using forecast prices and costs is based upon the price assumptions set out below. RPS used an internally generated price forecast that incorporates inflated United States dollars and is made quarterly based on a review of several industry sources.
Forecast Prices and Costs
Year
Forecast Dubai Crude
Posting Local Crude Sales Price
Crude Forecast Delta
US$ Cost Inflation Rate
$ / bbl $ / bbl % / Year % / Year
2012 105.80 104.10 - 2.00%
2013 101.30 99.60 -4.32% 2.00%
2014 96.80 95.10 -4.52% 2.00%
2015 96.61 94.91 -0.19% 2.00%
2016 98.63 96.93 2.12% 2.00%
2017 100.69 98.99 2.12% 2.00%
2018 102.79 101.09 2.12% 2.00%
2019 104.93 103.23 2.12% 2.00%
2020 107.11 105.41 2.11% 2.00%
2021 109.33 107.63 2.11% 2.00%
2022 111.60 109.90 2.11% 2.00%
2023 113.92 112.22 2.11% 2.00%
2024 116.28 114.58 2.11% 2.00%
2025 118.69 116.99 2.10% 2.00%
2026 121.15 119.45 2.10% 2.00%
2027 123.66 121.96 2.10% 2.00%
2028 126.21 124.51 2.10% 2.00%
2029 128.82 127.12 2.09% 2.00%
2030 131.48 129.78 2.09% 2.00%
2031 134.11 132.41 2.03% 2.00%
2032 136.80 135.10 2.03% 2.00%
2033 139.53 137.83 2.03% 2.00%
2034 142.32 140.62 2.02% 2.00%
2035 145.17 143.47 2.02% 2.00%
2036 148.07 146.37 2.02% 2.00%
2037 151.03 149.33 2.02% 2.00%
2038 154.05 152.35 2.02% 2.00%
Coastal’s weighted average realized sales price for crude oil for the year ended December 31, 2011 was $101.39.
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Reserves Reconciliation
The following table provides a summary of the changes in the Company’s reserves by product type as were calculated at December 31, 2011 compared with those calculated as of December 31, 2010, based upon the forecast price and cost assumptions set out above.
Light & Medium Crude Oil (mbbl) Natural Gas (bcf) NGLs (mbbl)
Gross Gross
Gross Proved
Gross Probable
Proved + Probable
Gross Proved
Gross Probable
Proved + Probable
Gross Proved
Gross Probable
Gross Proved +
Reserves Reserves Reserves Reserves Reserves Reserves Reserves Reserves ProbableDecember 31, 2010 14,489 12,654 27,143 - - - - - -Extensions and Improved Recovery
-
- - - - -
-
- - Technical Revisions (5,298) (8,119) (13,417) - - - - - - Discoveries 56,884 12,918 69,802 - - - - - - Acquisitions - - - - - - - - -Dispositions - - - - - - - - - Economic Factors - - - - - - - - - Production (3,586) - (3,586) - - - - - -
December 31, 2011 62,489 17,453 79,942 - - - - - -
Note: RPS did not provide the year-end reserves analysis for Coastal at year-end 2010, which was performed by Huddleston & Co.
Additional Information Relating to Reserves Data
Undeveloped Reserves Attributed in Current Year The following discussion generally describes the basis on which Coastal attributes proved and probable undeveloped reserves and its plans for developing those undeveloped reserves. Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., the cost of drilling a well or initiating a waterflood project) is required to render them capable of production and which fully meet the requirements of the reserves category (proved or probable) to which they are assigned. i) Proved Undeveloped Reserves Proved undeveloped Reserves are generally those reserves related to discoveries that are commercial that have not yet been developed, infill drilling locations and recovery from waterflood projects prior to production response. All proved undeveloped reserves are planned to be developed in 2012 and 2013. The following table summarizes the Company’s proved undeveloped Reserves that were first attributed in each of the most recent three financial years from the effective date of the Reserves Report and, in aggregate, before that time using forecast price and cost assumptions by production type.
Light & Medium Crude Oil (mbbl)
Total Proved Undeveloped Reserves
First Attributed Cumulative at Year End 2008 & Before 11,153 11,153 2009 - 7,183 2010 - 4,250 2011 19,736 21,576
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First Attributed Cumulative at Year End 2008 & Before 23,372 23,372 2009 - 17,701 2010 - 12,654 2011 6,771 7,744
ii) Probable Undeveloped Reserves Probable undeveloped reserves are generally those reserves tested or indicated by analogy to be productive infill drilling locations and lands contiguous to production or production attributable to higher recovery rates. All probable undeveloped reserves are planned to be developed in 2012 and 2013. The following table summarizes the Company’s probable undeveloped reserves that were first attributed in each of the most recent three financial years from the effective date of the Reserves Report and, in aggregate before that time using forecast price and cost assumptions by production type.
Light & Medium Crude Oil (mbbl)
Total Probable Undeveloped Reserves
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Significant Factors or Uncertainties Affecting Reserves Data The process of estimating reserves is complex. Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science. It requires significant judgments and decisions based on available geological, geophysical, engineering, and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and natural gas prices and costs change. Estimates are reviewed and revised, either upward or downward, as warranted by newly acquired information. The evaluation and drilling of hydrocarbon targets may be curtailed, delayed or cancelled by the unavailability or prevailing cost of drilling rigs or technical contractors, mechanical difficulties, adverse weather and ocean conditions, environmental issues, political or social unrest, technical hazards, such as unusual or unexpected formations or pressures or because of issues related to compliance with government regulations or requirements. Drilling may result in unprofitable efforts, not only with respect to dry wells, but also with respect to wells which, though yielding some hydrocarbons, are not sufficiently productive to economically justify commercial development. Furthermore, the successful completion of a well does not assure a profit on investment or the recovery of drilling, completion and operating costs. The reserve estimates provided by RPS that are contained herein were based on production forecasts, prices, and economic conditions applicable, as at December 31, 2011. Future Development Costs The following table provides a summary of the development costs during the next five years deducted in the estimation of future net revenue attributable to each of the reserves categories set out below:
Pd
Year
RESERVE CLASSIFICATION
Proved
(M$)
Probable
(M$)
Proved
+ Probable
(M$)
1 2012 226,836 0 226,8362 2013 13,268 18,287 31,5563 2014 0 0 0
4 2015 7,852 -7,852 05 2016 0 10,258 10,258
Totals 247,957 20,693 268,649
Based on forecast prices, Coastal estimates that its internally generated cash flow will be sufficient to fund the future development costs disclosed above. Coastal typically has available three sources of funding to finance its capital expenditure program: (i) internally generated cash flow from operations; (ii) debt financing when appropriate; and (iii) new equity issues, if available on favourable terms. Coastal does not expect that the costs of funding its capital expenditures will have a material effect on the economic viability of the development of any of its properties.
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Other Oil and Gas Information
Oil and Gas Properties and Wells
The following table summarizes the location of the Company’s interests as at December 31, 2011 in crude oil wells that are producing or that the Company considers to be capable of production.
Location Working Interest
Block G5/43 Gulf of Thailand 100%
Coastal has 100% working interest and operatorship in its offshore properties. The Company leases a majority of its offshore infrastructure, which is reflected in lease operating expenses. The Company plans to purchase processing facilities which are currently leased, the acquisition costs are included in the analysis.
Coastal’s wells to which reserves have been attributed and which are capable of producing but are not currently producing are provided in the table below. The offshore wells that are not producing were classified as shut-in because the wells had been drilled and were awaiting completion, which occurred in January and February of 2012.
Light and Medium Crude Oil (mbbl) Total Reserves
7 wells at Songkhla D field, Bua Ban North 17,171
Coastal’s producing and non- producing oil wells are set out in the table provided below.
Location Product Type
Gross Producing Wells
Net Producing Wells
Gross Non- producing Wells
Net Non- producing Wells
Songkhla – Gulf of Thailand
Light & Medium Crude Oil 24 24 12 12
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Properties with No Attributed Reserves The following table sets forth the Company’s undeveloped land holdings to which no proved reserves have been attributed as at December 31, 2011.
Location Working Interest Gross Acres Net Acres
Block G5/50 Gulf of Thailand 100% 137,000 137,000
The Company does not have any relinquishment requirements in the next twelve months. The Company has an obligation to drill one exploratory well on its G5/50 acreage before December 31, 2012. In 2011, Coastal’s realized average price for crude oil was $101.39/bbl and APICO’s realized price for natural gas was $8..96/Mcf. In 2010, Coastal’s realized average price for crude oil was $54.06/bbl and APICO’s realized price for natural gas was $7.07/Mcf. Coastal’s crude oil production is sold to credit worthy counterparties under contracts based on the Dubai benchmark price. APICO’s natural gas production is sold to PTT Public Company Ltd. under a gas sales agreement expiring in 2021. Crude oil is stored in floating storage tankers until it is offloaded by the buyer. Natural gas is transported through pipelines in the Kingdom of Thailand.
The key risks and uncertainties associated with the Company’s unproved properties include the risk that no commercial quantities of hydrocarbons may be discovered in the area before the exploration license expires, or the risk that in the event of a discovery, commodity prices render the discovery uneconomical at the time. Forward Contracts From time to time, Coastal may enter into hedging arrangements to mitigate commodity price risk and take advantage of opportunistic pricing. Coastal has a Hedging Committee comprised of three independent directors that reviews all hedging transactions prior to entry. As of March 27, 2012, the Company has hedges covering 0.42 million barrels of net production through September 2012 at a fixed price of $79.03 per barrel. The Company also has a costless collar in place covering an additional 0.67 million barrels with a floor price of $70.00 per barrel and a ceiling price of $119.10 per barrel. The reference instrument for the Company’s commodity hedging transactions is currently ICE Brent crude. Additional Information Concerning Abandonment and Reclamation Costs Coastal is required to remove production equipment and to restore land at the end of oil and natural gas operations. The Company estimates these costs in accordance with existing laws, contracts, and other policies. These obligations are initially measured at fair value, which is the discounted future value of the liability. This fair value is also capitalized as part of the cost of the related assets and amortized over the useful life of the assets. The Company expects to incur abandonment and reclamation costs on approximately 42 net wells over the course of developing its Proved and Probable Reserves. Asset retirement obligation (“ARO”) cost calculations were derived from management’s estimates and typical industry experience and practices. The deemed ARO liability for Coastal’s well sites and facilities is the sum of the calculated abandonment and reclamation liabilities adjusted for designated status as an active, inactive, abandoned, or problem site. An inflation rate of 2% was used in the fair value calculation.
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Total asset retirement cost calculated as of December 31, 2011 is estimated to be $55.4 million or $12.0 million when discounted at 10%. All of these costs have been deducted in estimating future net revenue. The Company expects to incur less than $0.5 million of ARO costs between 2012 and 2016. Tax Horizon Coastal has approximately $135.5 million in tax pools to apply against taxable income. Based upon planned capital expenditure programs and current commodity price assumptions, it is anticipated the Company will incur cash taxes of between 5 – 10% of operating cash flow under its current 2P production forecast. Capital Expenditures In 2011, Coastal incurred approximately $153.5 million of capital costs in total. In 2011, Coastal’s share of APICO’s capital costs was $4.8 million, which is comprised of exploration costs for unproved properties as well as 3D seismic acquisition costs.
Exploration and Development Activities As of December 31, 2011, the Company had drilled thirty three development wells, seven injection wells and eleven exploration wells in the Gulf of Thailand. It had participated in drilling four development wells and three exploratory wells (all three were dry holes) onshore Thailand. In 2012, the Company expects to continue to focus its resources in the Gulf of Thailand. Coastal’s overall objective for 2012 is to focus primarily on exploration and development activities and the advancement of reserves from the proved undeveloped and probable categories to the proved producing classification. Coastal has plans for 2012 to drill exploratory wells on several of its prospects. It is intended that Coastal’s capital program will be financed using cash flow from operations and will be adjusted on an ongoing basis to reflect operating results.
Production History The Company’s average gross daily production volume and total production volume for the year ended December 31, 2011, in respect of its offshore properties, before the deduction of royalties, for each of the periods indicated is set forth below.
Year Ended
Three Months Ended Three Months Ended Three Months Ended Three Months Ended DecemberMarch 31, 2011 June 30, 2011 September 30, 2011 December 31, 2011 31, 2011
Crude Oil (bbl/d) 8,325 7,340 10,191 13,386 9,825 Crude Oil (mbbl) 749.2 667.9 937.6 1,231.5 3,586.2
The Company’s per unit results on a quarterly basis for the periods indicated is set forth below.
Three Months Ended
Three Months Ended Three Months Ended Three Months Ended
Year Ended December
March 31, 2010 June 30, 2011 September 30, 2011 December 31, 2011 31, 2011 Crude Oil ($/bbl) Price
$94.89
$108.29 $103.02 $101.05 $101.39
Royalties $7.64 $8.41 $7.94 $9.37 $8.39 Operating Costs $29.06 $28.69 $34.25 $25.69 $28.94
Netback $58.19 $71.19 $60.83 $66.09 $64.06
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2012 Production Estimates
Production volumes in 2012 as estimated in the Company’s reserve forecast from RPS before deduction of royalties are set forth below.
Reserves Category Proved Reserves
Crude Oil (mbbl) Natural Gas (MMcf) NGLs (mbbl) Total (mboe)
Developed Producing 3,413.9 - - 3,413.9 Developed Shut-In 1,825.0 1,825.0 Developed Nonproducing 0.0 - - 0.0 Undeveloped 1,934.3 - - 1,934.3
Total Proved Reserves 7,173.2 - - 7,173.2
Probable Reserves 177.6 - - 177.6
Total Proved plus Probable - Reserves 7,350.8
- 7,350.8
Form 51-101 F3 Report of Management and Directors on Reserves Data and Other Information
Management of Coastal Energy Company (the Company) is responsible for the preparation and disclosure of information with respect to the Company's oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data which consists of the following:
(a) Proved and proved plus probable oil and gas reserves estimated as at December 31, 2011 using forecast prices and costs and the related estimated future net revenue; and
(b) Proved and proved plus probable oil and gas reserves estimated as at December 31, 2011 using constant prices and costs and the related estimated future net revenue.
An independent qualified reserves evaluator has evaluated the Company's reserves data. The report of the independent qualified reserves evaluator will be filed with securities regulatory authorities concurrently with this report.
The Reserves Committee of the board of directors of the Company has
(a) reviewed the Company's procedures for providing information to the independent qualified reserves evaluator;
(b) met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation, and
(c) reviewed the reserves data with management and the independent qualified reserves evaluator.
The Reserves Committee of the board of directors has reviewed the Company's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has, on the recommendation of the Reserves Committee, approved
(a) the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information;
(b) the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluators on the reserves data; and
(c) the content and filing of this report.
Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.
March 28, 2012
/s/ Randy L. Bartley /s/ William C Phelps Randy L. Bartley William C. Phelps President and Chief Executive Officer Chief Financial Officer /s/ Andrew L. Cochran /s/ L. Barnaby Smith Andrew L. Cochran L. Barnaby Smith Director, Reserves Committee Chair Director, Chairman of the Board
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APPENDIX “C”
EQUITY INVESTMENT DISCLOSURE The following is a summary of APICO’s reserves and future net revenue as of December 31, 2011 and the costs incurred by APICO during the year ended December 31, 2011 multiplied by 36.1 percent, being Coastal’s equity interest in APICO as of December 31, 2011. APICO’s reserves were independently evaluated by RPS Group Ltd.. The evaluation was prepared by RPS in accordance with standards contained in the COGE Handbook and the reserves definitions contained in NI 51-101. The pricing assumptions used in the forecast are set forth below. All of the reserves assigned to APICO are located in onshore Thailand. Coastal accounts for its investment in APICO using the equity method of accounting. As a result, pursuant to NI 51-101, Coastal is required to disclose the following information separately from its own reserves data and other oil and gas information. Summary of Company’s Share of APICO’s Oil and Gas Reserves Using Forecast Pricing as of December 31, 2011 A summary of the Company’s share of APICO’s reserves by product type based upon forecast price and cost assumptions, before and after applicable royalties, as at December 31, 2011, is presented below. Light and Medium Crude Oil Natural Gas Natural Gas Liquids Totals
Reserve Category
Gross (mbbl)
Net (mbbl)
Gross (bcf)
Net (bcf)
Gross (mbbl)
Net (mbbl)
Gross (mboe)
Net (mboe)
Proved Reserves: Onshore Developed Producing - - 33.0 33.0 169 169 5,663 5,663
Total Proved Reserves – 1P - - 43.3 43.3 222 222 7,440 7,440Probable Reserves:
Onshore Undeveloped
- - 89.8 89.8 461 461
17,197 17,197 Total Probable Reserves - - 89.8 89.8 461 461 17,197 17,197
Total Proved Plus Probable Reserves – 2P - - 133.1 133.1 683 683 22,859 22,859
The tables set forth below summarize the Company’s share of APICO’s future net revenue before taxes as of December 31, 2011, based on forecast prices and cost assumptions.
Net Present Value of Future Net Revenue Before Income Taxes (MM$), Discounted at Reserves Category 0% 5% 10% 15% 20%
After Income Taxes (MM$), Discounted at 0% 5% 10% 15% 20%
Unit Value ($/boe) Before Income Tax Discounted at 10%
Proved Reserves Onshore Developed Producing 221 176 145 122 105
152 122 101 85 74
$24.01
Total Proved Reserves – 1P 291 228 184 153 129 198 156 127 105 90 $23.25Probable Reserves Onshore Undeveloped 725 323 159 85 49 474 212 104 56 32 $8.61
Total Probable Reserves 725 323 159 85 49 474 212 104 56 32 $8.61 Total Proved Plus Probable Reserves – 2P 1016 552 343 237 178
671 368 231 161 122
$14.04
2
Before Income Taxes (MM$),
Discounted at Reserves Category 10%
Unit Value ($/boe) Before Income Tax Discounted at 10%
Proved Reserves Natural Gas & NGLs 184 $23.25
Probable Reserves Natural Gas & NGLs 159 $8.61
Total Proved Plus Probable Reserves – Natural Gas & NGLs 343
$14.04
Forecast Prices and Costs Future net revenue in respect of Coastal’s share of APICO’s reserves, calculated using forecast prices and costs, is based upon the price assumptions set out below. RPS used their own internal price forecasts.
Period Year Thailand Onshore Gas
Price ($/Mcf)
Thailand Condensate
Price ($/bbl)
1 2012 8.44 102.68 2 2013 8.13 98.44 3 2014 7.81 94.19 4 2015 7.80 94.03 5 2016 7.79 95.92 6 2017 7.93 97.86 7 2018 8.08 99.84 8 2019 8.22 101.85 9 2020 8.37 103.91
10 2021 8.12 106.01 11 2022 8.27 108.15 12 2023 8.42 110.33 13 2024 8.58 112.56 14 2025 8.73 114.83 15 2026 8.90 117.15 16 2027 9.06 119.51 17 2028 9.23 121.92 17 2029 9.40 124.38 19 2030 9.57 126.88 20 2031 9.75 129.44 21 2032 9.93 132.05 22 2033 10.12 134.71 23 2034 10.30 137.42 24 2035 10.50 140.19 25 2036 10.69 143.02
APICO’s weighted average realized sales price for natural gas for the year ended December 31, 2011 was $8.96/Mcf.