Caracal Energy Inc. - Reserves & Resources Year-end Evaluation

CALGARY, Feb. 26, 2014 /CNW/ - Caracal Energy Inc. ("Caracal" or the "Company") (LSE:CRCL) is pleased to announce today the results of its 2013 year-end oil and gas reserve and contingent resource evaluation.

The independent reserves and resources evaluation was provided by McDaniel & Associates Consultants Ltd. ("McDaniel") and demonstrates a significant increase in volumes from our prior year evaluation with an effective date December 31, 2012.

Highlights include:

  • Gross Lease Reserves
    • Proven ("1P") of 47.4 million barrels ("MMB"), an increase of 64% *
    • Proved plus Probable ("2P") of 179.6 MMB, an increase of 101%
    • Proved plus Probable plus Possible ("3P") of 388.6 MMB, an increase of 94%
  • Caracal Net Entitlement Reserves
    • 1P of 18.8 MMB, an increase of 67%
    • 2P of 64.3 MMB, an increase of 102%
    • 3P of 118.1 MMB, an increase of 85%
  • Caracal's Net Present Value attributable to Reserves (discounted at 10% before tax) - all amounts in U.S. Dollars
    • 1P of $688 million, an increase of 24%
    • 2P of $1,722 million, an increase of 61%
    • 3P  of $3,224 million, an increase of 71%

*All comparisons above are relative to the Company's December 31, 2012 reserves and resources evaluation, provided by GLJ Petroleum Consultant Ltd. ("GLJ") in a statement of reserves and contingent resources effective December 31, 2012 and included in the Company's United Kingdom prospectus.  When compared with the GLJ report on reserves and contingent resources with effective date December 31, 2012, prepared in accordance with the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and National Instrument 51-101 - Reserves Data and Other Oil & Gas Information ("NI 51-101") (the "COGE Report"), issued on June 28, 2013, and as included in the Company's final long-form prospectus as dated and filed with the Alberta Securities Commission on July 2, 2013, the 2013 year-end oil and gas reserve and contingent resource evaluation represents the following percentage increases as compared to the COGE Report: For Gross Lease Reserves: (i) 64% for 1P, (ii) 119% for 2P, and (iii) 111% for 3P; for Caracal Net Entitlement Reserves: (i) 67% for 1P, (ii) 127% for 2P, and (iii) 107% for 3P; and for Net Present Value attributable to Reserves: (i) 24% for 1P, (ii) 61% for 2P, and (iii) 75% for 3P.

Gary Guidry, Chief Executive Officer of Caracal, said:
"We are pleased to report another year of significant growth in oil reserve volumes on our Production Sharing Contracts ("PSC") in Chad. Since 2011 when the PSCs were awarded, we have grown gross lease 2P Reserves volumes by 439%. We look forward to delivering further growth as we continue to execute on our extensive exploration, appraisal and development programs."

The following tables summarize certain information contained in the independent reserves and resources report prepared by McDaniel & Associates Consultants Ltd. ("McDaniel" as of December 31, 2013 (collectively, the "McDaniel Report" or the "Report"). The Report was prepared in accordance with definitions, standards and procedures contained in the COGE Handbook and NI 51-101. Additional reserve information as required under NI 51-101 will be included in the Company's Annual Information Form which will be filed on SEDAR on or before March 31, 2014.

Unless otherwise specified, all dollar values are in millions of US dollars ($MM).

Summary of Oil Reserves and Resources:

The Net Present Values included in the table below were based on oil price forecasts, effective July 1, 2013, provided by McDaniel.

SUMMARY OF CRUDE OIL RESERVES
AS AT DECEMBER 31, 2013
 
  Summary of Reserves (in MMB)(1)
  Gross (100%)(2)(5)   Company's Net Participating
Interest(3)(5)
  Company's net
entitlement(4)(5)
  PDP 1P 2P 3P   PDP 1P 2P 3P   PDP 1P 2P 3P
Asset                            
Mangara Field - 22.2 69.9 145.5   - 11.1 34.9 72.8   - 9.6 24.9 45.0
Badila Field 9.1 21.3 44.7 95.3   4.5 10.6 22.4 47.6   3.8 7.5 14.1 25.3
Krim Field - 3.9 19.0 42.7   - 1.9 9.5 21.4   - 1.8 7.7 15.2
Kibea Field - - 45.9 105.0   - - 23.0 52.5   - - 17.6 32.6
                             
Total Reserves 9.1 47.4 179.6 388.6   4.5 23.7 89.8 194.3   3.8 18.8 64.3 118.1

Notes:
(1)      All of the Company's proved, probable and possible reserves have been classified as light and
medium crude oil. The Company has no heavy crude oil. Based on current market conditions in
Chad, neither reserves or values have been attributed to gas or natural gas liquid volumes.
However, the Company has rights to monetise gas volumes and is currently discussing and
assessing this market potential for the future.
(2)      Gross is the total marketable reserves assigned to the Company's concessions.
(3)      The Government of Chad initially elected to acquire a 25 percent participating interest in the Badila
and Mangara EXAs before selling 10 percent to Glencore. McDaniel has assumed, for the purposes
of estimating the Company's participating interest in any future EXAs which may be granted under
each PSC, that the Government of Chad will elect to acquire a 25 percent participating interest in
each EXA. Accordingly, the Company's and Glencore's participating interests have been assumed
to be 50 percent and 25 percent, respectively, of the gross lease interest in future developments.
(4)      Net reserves are the Company's share of Cost Oil recovery and Profit Oil. A portion of the reported
reserves will increase as oil prices decrease (and vice versa) as the barrels necessary to achieve
cost recovery change with prevailing oil prices. Under the COGE Handbook, using the economic
interest method, "Net" as depicted above is equivalent to "company net" and, in the particular
case of the Company's PSCs, "company gross".
(5)      Columns may not add due to rounding.

SUMMARY OF CRUDE OIL CONTINGENT RESOURCES
AS AT DECEMBER 31, 2013
 
    Summary of Contingent Resource (in MMB)(1)
    Gross (100%)(2)(4)   Company's Net Participating
Interest(3)(4)
    1C   2C   3C   1C   2C   3C
Asset                        
Maku Field    0.3   2.2   4.7   0.2   1.1   2.3
Sako North Field    0.1   0.7   2.0   0.0   0.4   1.0
Tega Field    0.2   1.3   3.6   0.1   0.6   1.8
Total     0.6   4.2   10.3   0.3   2.1   5.2

Notes:  
(1)   All of the Company's contingent resources have been classified as light
and medium crude oil. The Company has no heavy crude oil. Based on
current market conditions in Chad, neither contingent resources or values
have been attributed to gas or natural gas liquid volumes. However, the
Company has rights to monetise gas volumes and is currently discussing
and assessing this market potential for the future.
(2)   Gross is the total marketable contingent resources assigned to the
Company's concessions.
(3)    The Government of Chad initially elected to acquire a 25 percent
participating interest in the Badila and Mangara EXAs before selling
10 percent to Glencore. McDaniel has assumed, for the purposes of
estimating the Company's participating interest in any future EXAs
which may be granted under each PSC, that the Government of Chad
will elect to acquire a 25 percent participating interest in each EXA.
Accordingly, the Company's and Glencore's participating interests
have been assumed to be 50 percent and 25 percent, respectively,
of the gross lease interest in future developments.
(4)     Columns may not add due to rounding.

Oil Reserves Evaluation Summary:

SUMMARY OF CRUDE OIL RESERVES
AS AT DECEMBER 30, 2013
FORECAST PRICES AND COSTS
 
Light & Medium Crude Oil(1)
Reserves Category Gross Lease(2)(5)   Participating
Interest(3)(5)
  Company's Net
Entitlement(4)(5)
(MB)(6)   (MB)(6)   (MB)(6)
Proved Developed Producing          
Mangara -   -   -
Badila 9,076              4,538               3,750
Krim -   -   -
Kibea -   -   -
Total Proved Developed Producing             9,076               4,538               3,750
Proved Undeveloped          
Mangara            22,217                11,109               9,559
Badila            12,204                6,102               3,749
Krim             3,886                1,943                1,783
Kibea -   -   -
Total Proved Undeveloped           38,307               19,154               15,091
Total Proved           47,384             23,692              18,840
           
Probable          
Mangara           47,678             23,839               15,321
Badila           23,450               11,725                6,591
Krim             15,143                7,571               5,907
Kibea            45,916             22,958              17,640
Total Probable          132,187             66,093             45,459
Total Proved plus Probable          179,570             89,785             64,299
           
Possible          
Mangara           75,627              37,813             20,083
Badila           50,540             25,270               11,255
Krim           23,699               11,849               7,539
Kibea            59,127             29,564              14,927
Total Possible        208,993           104,497             53,805
Total Proved plus Probable plus Possible        388,563           194,282             118,104

Notes:  
(1)     All of the Company's proved, probable and possible reserves have been classified as light and medium
crude oil. The Company has no heavy crude oil. Based on current market conditions in Chad, neither
reserves or values have been attributed to gas or natural gas liquid volumes. However, the Company
has rights to monetize gas volumes and is currently discussing and assessing this market potential for
the future.
(2)    Gross lease are the total marketable reserves assigned to the Company's concessions.
(3)      The Government of Chad initially elected to acquire a 25 percent participating interest in the Badila and
Mangara EXAs before selling 10 percent to Glencore. McDaniel has assumed, for the purposes of
estimating the Company's participating interest in any future EXAs which may be granted under each
PSC, that the Government of Chad will elect to acquire a 25 percent participating interest in each EXA.
Accordingly, the Company's and Glencore's participating interests have been assumed to be 50 percent
and 25 percent, respectively, of the gross lease interest in future developments.
(4)  Net reserves are the Company's share of Cost Oil recovery and Profit Oil. Under the COGE Handbook,
using the economic interest method, "Net" as depicted above is equivalent to "company net" and, in the
particular case of the Company's PSCs, "company gross".
(5)   Columns may not add due to rounding.
(6)  "MB" refers to thousands of barrels.

SUMMARY OF NET PRESENT VALUE OF FUTURE NET REVENUE (US$)
AS AT DECEMBER 31, 2013
FORECAST PRICES AND COSTS
 
Before and After Taxes Before and After Income Tax(1)(2)(3) Discounted at
(millions of dollars)
Unit Value Before
Deducting
Income Taxes
Discounted at
10%/year
Reserves Category
  0% 5% 10% 15% 20% ($/boe)
Proved Developed Producing            
Mangara  - - - - - -
Badila 222 208 196 185 176 52.30
Krim - - - - - -
Kibea - - - - - -
Total Proved Developed Producing 222 208 196 185 176 52.30
Proved Undeveloped            
Mangara  411 337 281 237 202 29.42
Badila 224 203 185 170 157 49.36
Krim 44 33 25 20 15 14.29
Kibea - - - - - -
Total Proved Undeveloped 679 573 492 427 375 32.59
Total Proved 901 782 688 612 551 36.51
             
Probable            
Mangara  805 616 484 389 319 31.62
Badila 346 296 258 227 203 39.13
Krim 195 142 104 78 59 17.65
Kibea 490 306 188 109 56 10.66
Total Probable  1,837 1,361 1,035 804 637 22.76
Total Proved plus Probable  2,738 2,143 1,723 1,416 1,188 26.79
             
Possible            
Mangara  1128 786 577 442 350 28.75
Badila 738 540 414 330 270 36.81
Krim 366 248 173 123 90 22.88
Kibea 836 518 337 228 158 22.60
Total Possible(3) 3,068 2,092 1,501 1,123 868 27.91
Total Proved plus Probable plus Possible(3) 5,806 4,235 3,224 2,539 2,056 27.30

Notes:  
(1)     The Government of Chad initially elected to acquire a 25 percent participating interest in the Badila and Mangara EXAs
before selling 10 percent to Glencore. McDaniel has assumed, for the purposes of estimating the Company's participating
interest in any future EXAs which may be granted under each PSC, that the Government of Chad will elect to acquire a 25
percent participating interest in each EXA. Accordingly, the Company's and Glencore's participating interests have been
assumed to be 50 percent and 25 percent, respectively, of the gross lease interest in future developments.
(2)     Pursuant to the terms of the DOB/DOI PSC and the Doseo/Borogop PSC, the Government of Chad's Profit Oil allocation
is inclusive of income tax.
(3)      Columns may not add due to rounding.

TOTAL COMPANY FUTURE NET REVENUE (UNDISCOUNTED) (US$)
AS AT DECEMBER 31, 2013
FORECAST PRICES AND COSTS
                             
Category           Capital and    Future Net        Future Net    Future Net 
   Operating Abandonment  Revenue   Income Revenue  Revenue 
Revenue  Costs Costs  Before Tax  Tax After Tax  Discounted @ 
 ($000's)  ($000's) ($000's) ($000's)  ($000's) ($000's) 10% ($000's)
Proved Reserves    1,619,300   405,200   313,400   900,900   -   900,900   687,800
Proved Plus Probable Reserves    5,416,100   1,516,200   1,162,300   2,737,600   -   2,737,600   1,722,400
Proved Plus Probable Plus Possible Reserves    10,484,200   3,044,200   1,634,300   5,805,700   -   5,805,700   3,223,900

Note:  
(1)     Pursuant to the terms of the DOB/DOI PSC and the Doseo/Borogop PSC, the Government of Chad's Profit Oil allocation is inclusive of income tax.

FUTURE NET REVENUE BY PRODUCTION GROUP (US$)
AS AT DECEMBER 31, 2013
FORECAST PRICES AND COSTS
             
Category   Production Group(2)   Future Net Revenue
Before Income
Taxes (discounted
at 10% year)
($000's)
  Unit Value(1)
($/boe)
Proved Reserves   Light and Medium Crude Oil
(including solution gas and other
by-products)
  687.8   36.51
Proved Plus Probable Reserves   Light and Medium Crude Oil
(including solution gas and other
by-products)
  1,722.4   26.79
Proved Plus Probable Reserves
Plus  Possible Reserves
  Light and Medium Crude Oil
(including solution gas and other
by-products)
  3,223.9   27.30

Notes:  
(1)    The unit values are based on the Company's net reserve volumes.
(2)    All of the Company's proved, probable and possible reserves have been classified as light and medium
crude oil. The Company has no heavy crude oil. Based on current market conditions in Chad neither
reserves or values have been attributed to gas or natural gas liquid volumes. However, the Company
has rights to monetize gas volumes and is currently discussing and addressing this market potential
for the future.

PRICING ASSUMPTIONS

The forecast cost and price assumptions assume changes in wellhead selling prices and take into account inflation with respect to future operating and capital costs. McDaniel has employed the following price and inflation rate assumptions as of July 1, 2013 where evaluating the Company's reserves data:

Year   Brent Reference
Price(1) (US$/bbl)
  Realized
Price(1)
  Inflation
Rates(2)
%/Year
2014     105.00   90.87   2
2015     102.50   88.91   2
2016     100.20   86.55   2
2017     97.70   82.00   2
2018     98.00   80.24   2
2019     96.60   81.11   2
2020     98.50   82.77   2
2021     100.50   83.82   2
Thereafter     +2%/year        

Notes:  
(1)    McDaniel has assumed a reference price of Brent
(in US$) and utilized the McDaniel January 1, 2014
Price Forecast. The realized price is forecast to be
95 percent of Brent minus the estimated pipeline
transportation tariff of US$7.09/bbl and the variable
ITA Badila/Mangara and ITA East Doseo tariffs. The
realized price given is the average for all the
properties in McDaniel's 2P case.
(2)    Inflation rates for forecasting expenditure prices and costs.

Reserves & Resources - Additional Information:

Reserves Classification

The oil reserves estimates presented in this press release have been based on the Canadian reserves definitions and guidelines prepared by the Standing Committee on Reserves Definitions of the CIM (Petroleum Society) as presented in the COGE Handbook. A summary of those definitions is presented below.

Reserves Categories

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on

  • analysis of drilling, geological, geophysical and engineering data;
  • the use of established technology; and
  • specified economic conditions, which are generally accepted as being reasonable, and shall be disclosed.

Reserves are classified according to the degree of certainty associated with the estimates.

  • Proved reserves are 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 are 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 plus probable reserves.
  • Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. Other criteria that must also be met for the categorization of reserves are provided in the COGE Handbook.

Development and Production Status

Each of the reserves categories (proved, probable and possible) may be divided into developed and undeveloped categories:

  • Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.
  • Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
  • Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.
  • Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.
  • In multi-well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to individual reserves entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest-level sum of individual entity estimates for which reserves estimates are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

  • at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves. This category of reserves can also be denoted as 1P;
  • at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves. This category of reserves can also be denoted as 2P; and
  • at least a 10 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable plus possible reserves. This category of reserves can also be denoted as 3P. Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in the COGE Handbook.

Contingent Resources Classification

The assessment of the contingent resources in this press release were based on the resource definitions presented in the COGE Handbook Section 5 and are restated below.

Contingent resources are defined as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent resources are further classified in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status.

Uncertainty Categories

Estimates of resources always involve uncertainty, and the degree of uncertainty can vary widely between accumulations/projects and over the life of a project. Consequently, estimates of resources should generally be quoted as a range according to the level of confidence associated with the estimates. An understanding of statistical concepts and terminology is essential to understanding the confidence associated with resources definitions and categories. The range of uncertainty of estimated recoverable volumes may be represented by either deterministic scenarios or a probability distribution. Resources should be provided as low, best and high estimates, as follows:

  • Low Estimate - This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate.
  • Best Estimate - This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.
  • High Estimate - This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

Contingent Resource Categories

For Contingent Resources, the general cumulative terms low/best/high estimates are denoted as 1C/2C/3C respectively. No specific terms are defined for incremental quantities within Contingent Resources.

Risks and Uncertainties

The recovery of resources is subject to significant risk and uncertainty. There is no certainty that it will be commercially viable to produce any portion of the contingent resources reported herein.  The contingent resource estimates in this press release are not currently classified as reserves primarily due to economic considerations. In order to develop Kibea, Maku, Tega, and Sako North construction of a pipeline of approximately 500 kilometres at an estimated cost of US$381 million is required.

BOE

This press release includes references to BOEs. References to "BOE" may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet of gas to one barrel of oil is based on an approximation of energy equivalence conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head.

Cautionary Statements

Certain information contained in this press release constitutes forward-looking information or statements including, without limitation, information and statements respecting: drilling operations, anticipated cash flow, future investment objectives, anticipated oil and gas pricing, expected inflation and future foreign exchange rates. Statements relating to "reserves" and "resources" are forward-looking information as they involve the implied assessment, based on certain estimates and assumptions that, among others, the reserves and resources described exist in the quantities predicted or estimated. Forward-looking information and statements are often, but not always, identified by the use of words such as "anticipate", "seek", "believe", "expect", "hope", "plan", "intend", "forecast", "target", "project", "guidance", "may", " might", "will", "should", "could", "estimate", "predict" or similar words or expressions suggesting future outcomes or language suggesting an outlook. By their very nature, forward-looking information and statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking information and statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to vary materially from the forward-looking information or statements. These factors include, but are not limited to: the volatility of oil and gas prices; production and development costs; capital expenditures; the imprecision of reserve and resource estimates and estimates of recoverable quantities of oil, natural gas and liquids; the Company's ability to replace and expand oil and gas reserves; environmental claims and liabilities; incorrect assessments of value when making acquisitions or dispositions; increases in debt service charges; the loss of key personnel; the marketability of production; defaults by third party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates; inadequate insurance coverage; compliance with environmental laws and regulations; changes in tax and royalty laws; the Company's ability to access external sources of debt and equity capital; and the Company's ability to obtain equipment in a timely manner to carry out development activities. Further information regarding these factors may be found under the headings "General Advisory", "Reserves and Resources Advisory" and "Risk Factors" in the Company's final Canadian prospectus dated July 2, 2013 available under the Company's profile on SEDAR (www.sedar.com) and the final UK prospectus dated June 28, 2013 available on the Company's website (to non-Canadian viewers). Readers are cautioned that the foregoing list of factors that may affect future results is not exhaustive. When relying on these forward-looking statements to make decisions with respect to the Company, investors and others should also carefully consider information set forth in the section "Forward-Looking Statements" of the Company's prospectuses respecting the assumptions upon which the Company bases certain forward-looking information and the uncertainties inherent in such assumptions. The Company does not assume responsibility for the accuracy and completeness of the forward-looking information or statements and such information and statements should not be taken as guarantees of future outcomes. Subject to applicable securities laws, the Company does not undertake any obligation to revise this forward-looking information or these forward-looking statements to reflect subsequent events or circumstances. This cautionary statement expressly qualifies the forward-looking information and statements contained in this press release. The estimates of reserves and future net revenue for individual properties may not reflect the same level of confidence as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

For more information about the Company including further risk factors, please consult Caracal's public filings at www.sedar.com and for certain foreign investors at Caracal's website www.caracalenergy.com

 

SOURCE Caracal Energy Inc.

For further information:


Caracal Energy Inc.
Gary Guidry, President and Chief Executive Officer
Trevor Peters, Chief Financial Officer
+1 403-724-7200

Longview Communications - Canadian Media Enquiries
Alan Bayless
Joel Shaffer
+1 604-694-6035
+1 416-649-8006

FTI Consulting - UK Media Enquiries
Ben Brewerton / Ed Westropp
+ 44 (0) 207 8313 3113
caracalenergy.sc@fticonsulting.com