Delphi Energy Releases Year End 2012 Reserves and Provides Bigstone Montney Update

Delphi Energy Releases Year End 2012 Reserves and Provides Bigstone Montney 
CALGARY, ALBERTA -- (Marketwire) -- 02/28/13 -- Delphi Energy Corp.
(TSX:DEE) ("Delphi" or the "Company") is pleased to report its crude
oil and natural gas reserves information for the year ended December
31, 2012. 
2012 was a year of significant achievements for Delphi with the
initial development of its Montney play at Bigstone. The Company
brought three horizontal Montney wells on production through 100
percent owned and constructed facilities and associated gas gathering
systems during the year. Success on this play has translated into
significant reserve additions. 

--  Replaced 2012 production of 8,276 barrels of oil equivalent per day
    ("boe/d") (3.0 million boe) by 2.0 times with total proved plus probable
    reserve additions of 11.9 million boe and dispositions and revisions of
    5.9 million boe; 
--  Increased total proved plus probable reserves by seven percent to 43.0
    million boe compared to 2011. Total proved reserves decreased by five
    percent to 23.8 million boe compared to 25.1 million boe in 2011; 
--  Increased total proved plus probable Bigstone Montney reserves by 233
    percent to 11.0 million boe compared to 3.3 million boe in 2011; 
--  Achieved finding and development costs ("F&D") including changes in
    future development costs ("FDC") of $16.35 per boe for total proved plus
    probable reserves. Including dispositions in the year, finding,
    development and acquisition costs ("FD&A") including changes in FDC were
    $18.03 per boe for total proved plus probable reserves; 
--  Increased total proved plus probable reserve liquids (light and medium
    crude oil and natural gas liquids) weighting to 24.2 percent in 2012
    from 22.9 percent in 2011; 
--  Successfully drilled and completed two additional Montney horizontal
    wells in the first quarter of 2013, utilizing a slickwater hybrid frac
    system resulting in a combined final test rate of 13.0 million cubic
    feet per day ("mmcf/d") of raw gas and 1,100 barrels per day ("bbls/d")
    of wellhead condensate. 

Reserves Summary 
GLJ Petroleum Consultants Ltd. ("GLJ"), the Company's independent
petroleum engineering firm, has evaluated Delphi's crude oil, natural
gas and natural gas liquids reserves as at December 31, 2012 and
prepared a reserves report in accordance with National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" and the
"Canadian Oil and Gas Evaluation Handbook". 
To view the Reserves Summary graph, please visit the following link: 
The following is summary reserves information detailed in the GLJ
reserves report at December 31, 2012: 

                                           December 31, 2012                
                           Light and Natural Gas Natural Gas     Total      
                          Medium Oil                 Liquids            % of
Reserves(1)                   (mbbls)      (mmcf)     (mbbls) (mboe)(2)  P+P
  Developed Producing            520      65,923       2,433    13,941    32
  Developed Non-producing          -       5,283         236     1,117     3
  Undeveloped                    171      38,162       2,207     8,738    20
Total Proved                     691     109,368       4,876    23,796    55
Probable                         326      86,427       4,536    19,266    45
Total Proved Plus Probable     1,017     195,795       9,412    43,062   100
(1) Delphi's reserves represent the operated and non-operated working       
    interest share of reserves before deduction of royalties and include any
    royalty interests of the Company.                                       
(2) Oil equivalent amounts have been calculated using a conversion rate of  
    six thousand cubic feet of natural gas to one barrel of oil (6:1).      

Net Present Value of Reserves 
The estimated future net revenues associated with Delphi's reserves
at December 31, 2012, based on the GLJ January 1, 2013 price
forecast, are summarized in the following table. 

                                                          Unit Value Before 
                     Net Present Values of Future Net        Income Tax     
                          Revenue Before Income             Discounted at   
                      Taxes Discounted at (%/year)           10%/year(2)    
($ millions)(1)       0%      5%     10%     15%     20%   ($/boe)  ($/mcfe)
 Producing         248.6   196.8   163.3   140.1   123.2     14.23      2.37
Developed Non-                                                              
 Producing          17.0    10.7     7.4     5.5     4.2      7.57      1.26
Undeveloped        132.7    73.3    41.4    22.6    10.9      5.52      0.92
Total Proved       398.3   280.8   212.1   168.2   138.3     10.63      1.77
Probable           443.3   240.4   150.8   103.3    74.8      9.22      1.54
Total Proved                                                                
 Plus Probable     841.6   521.2   362.9   271.5   213.1     10.00      1.67
(1) The estimated future net revenues are before the deduction of estimated 
    future site restoration costs but are reduced for estimated future      
    abandonment costs for reserve wells and estimated capital for future    
    development associated with the reserves. The estimated values disclosed
    do not necessarily represent fair market value.                         
(2) Unit values are calculated using net reserves defined as Delphi's       
    working interest share after deduction of royalty obligations plus      
    Delphi's royalty interests.                                             

Reserves Reconciliation 
The following reconciliation of Delphi's reserves compares changes in
the Company's reserves at December 31, 2011 to the reserves at
December 31, 2012, each evaluated in accordance with National
Instrument 51-101 definitions. 

                     Light and Associated and                               
                        Medium Non-Associated    Natural Gas      Total Oil 
                     Crude Oil            Gas        Liquids     Equivalent 
Proved                   (mbbl)         (mmcf)         (mbbl)         (mboe)
December 31,                                                                
 2011                    1,913        114,791          4,029         25,074 
Extensions and                                                              
 Recovery                    -         19,598          1,525          4,791 
 Revisions                  52          1,393             27            311 
Discoveries                  -              -              -              - 
Acquisitions                 -              -              -              - 
Dispositions            (1,018)        (7,590)          (138)        (2,421)
Economic Factors            (1)        (5,066)           (86)          (931)
Production                (255)       (13,758)          (481)        (3,029)
December 31,                                                                
 2012                      691        109,368          4,876         23,796 
                     Light and Associated and                               
                        Medium Non-Associated    Natural Gas      Total Oil 
                     Crude Oil            Gas        Liquids     Equivalent 
Probable                 (mbbl)         (mmcf)         (mbbl)         (mboe)
December 31,                                                                
 2011                      765         71,072          2,498         15,108 
Extensions and                                                              
 Recovery                    -         29,670          2,183          7,128 
 Revisions                 (56)        (8,317)           (83)        (1,526)
Discoveries                  -              -              -              - 
Acquisitions                 -              -              -              - 
Dispositions              (382)        (2,273)           (43)          (804)
Economic Factors            (1)        (3,724)           (18)          (639)
Production                   -              -              -              - 
December 31,                                                                
 2012                      326         86,427          4,536         19,267 
                     Light and Associated and                               
                        Medium Non-Associated    Natural Gas      Total Oil 
Proved Plus          Crude Oil            Gas        Liquids     Equivalent 
 Probable                (mbbl)         (mmcf)         (mbbl)         (mboe)
December 31,                                                                
 2011                    2,678        185,862          6,527         40,182 
Extensions and                                                              
 Recovery                    -         49,268          3,707         11,919 
 Revisions                  (4)        (6,924)           (56)        (1,215)
Discoveries                  -              -              -              - 
Acquisitions                 -              -              -              - 
Dispositions            (1,400)        (9,863)          (182)        (3,225)
Economic Factors            (2)        (8,790)          (103)        (1,570)
Production                (255)       (13,758)          (481)        (3,029)
December 31,                                                                
 2012                    1,017        195,795          9,412         43,062 

Finding and Development Costs 
Finding and development costs in 2012, 2011, and averages for the
three most recent financial years, were as follows: 

                             2012              2011           2010-2012     
                                 Proved            Proved            Proved 
                                   Plus              Plus              Plus 
                        Proved Probable   Proved Probable   Proved Probable 
Capital (unaudited) ($                                                      
  Exploration and                                                           
   Development ("E&D")                                                      
   Costs                83,728   83,728  114,477  114,477  303,155  303,155 
  Change in Future                                                          
   Development Costs                                                        
   ("FDC") related to                                                       
   E&D                  31,644   65,642    1,473   10,112   65,995  121,800 
  Total E&D Costs      115,372  149,370  115,950  124,589  369,150  424,955 
  Acquisition Costs                                                         
   (unaudited)             139      139      273      273      431      431 
  Disposition Costs                                                         
   (unaudited)         (34,664) (34,664) (12,873) (12,873) (47,783) (47,783)
  Change in FDC                                                             
   related to                                                               
   Acquisitions and                                                         
   ("A&D")              (8,299)  (8,299)  (1,162)  (1,935)  (9,638) (11,491)
  Total A&D Costs      (42,823) (42,823) (13,762) (14,535) (56,990) (58,843)
  Total Costs           72,549  106,547  102,188  110,054  312,160  366,112 
Reserves (mboe)                                                             
  Reserve Additions(1)   4,172    9,134    5,882    9,450   17,990   29,157 
  Acquisitions and                                                          
   Dispositions         (2,421)  (3,225)    (291)    (551)  (2,993)  (4,267)
  Total Reserve                                                             
   Additions             1,751    5,909    5,591    8,899   14,997   24,890 
Finding and                                                                 
 Development Costs                                                          
  E&D, excluding                                                            
   change in FDC         20.07     9.17    19.46    12.11    16.85    10.40 
  E&D, including                                                            
   change in FDC                                                            
   related to E&D        27.66    16.35    19.71    13.18    20.52    14.57 
   Acquisitions and                                                         
   including change in                                                      
   FDC                   41.45    18.03    18.28    12.37    20.81    14.71 

Total exploration and development costs incurred in the most recent
financial year and the change during that year in estimated future
development costs generally will not reflect the total cost of
reserve additions in that year. 
(1) Includes extensions and improved recovery, technical revisions
and economic factors. 
Net Asset Value 
The estimated net asset value of the Company at December 31, 2012 has
been calculated using before tax, net present value of reserves
discounted at ten percent as follows: 

($thousands except share count and per share value)                         
Estimated future net revenues of proved plus probable                       
 reserves (1)                                                       362,860 
Undeveloped land (2)                                                 65,319 
Mark-to-market value of hedging contracts(3)                         (3,789)
In-the-money option proceeds (4)                                        573 
Total asset value                                                   424,963 
Bank debt plus working capital deficiency (unaudited)               (92,815)
Net asset value                                                     332,148 
Common shares outstanding and in-the-money options              153,896,798 
Net asset value per share                                              2.16 
(1) Discounted at 10 percent and before deducting future income tax expenses
    and reclamation costs. The Company estimates it has approximately $315  
    million of tax deductions available to offset future taxable income.    
(2) Undeveloped land was determined by an independent land valuation report 
    by Seaton-Jordan & Associates Ltd. Fair value was determined according  
    to paragraph (e), subsection (1), Section 5.9 of NI 51-101 and further  
    detailed in Companion Policy 51-101CP. At December 31, 2012 Delphi had  
    an interest in 196,543 net acres of undeveloped land.                   
(3) Includes both physical and financial positions at December 31, 2012.    
(4) In-the-money option proceeds are based on the closing December 31, 2012 
    share price of $1.14.                                                   

Delphi is also pleased to provide the following operations update. 
At East Bigstone, Delphi recently brought on production its fourth
horizontal Montney well. The 15-10-60-23W5 well was drilled during
the fourth quarter of 2012 to a total depth of 4,455 metres with a
horizontal lateral length of 1,424 metres. The well was completed
with a 20 stage slickwater hybrid completion. Total drill and
completion costs are estimated to be $8.3 million. During the seven
day clean-up flow period, prior to running production tubing, the
well had recovered approximately 29 percent of the initial load frac
water volumes. The well was brought on production on January 27, 2013
through the Company's 100 percent owned compression and dehy facility
and over the first 12 full days on production, averaged 4.2 mmcf/d of
raw gas (rate on the last full day of production was consistent with
the 12 day average), with associated field condensate production over
the same period averaging 50 barrels per million cubic feet
("bbls/mmcf") of raw gas. Including plant recovered liquids
(estimated to be 36 bbls/mmcf raw gas), the Company estimates total
natural gas liquids ("NGL's) production to be 86 bbls/mmcf of raw gas
production (100 bbls/mmcf sales) consisting of 70 percent field and
plant recovered condensate. Total production rate over this initial
period was approximately 990 boe/d (37 percent NGL's). 
Initial results of this well, and particularly the new completion
design employed, are very encouraging based on the shallower initial
declines exhibited on the 15-10 well (as compared to the first three
wells drilled in East Bigstone which were completed with gelled oil
fracs), as well as the higher initial field condensate to gas
production ratio. 
The Company has just concluded fracturing operations on its second
horizontal Montney well of the winter season in East Bigstone. The
10-27-60-23W5 well was drilled during the first quarter of 2013 to a
total depth of 5,260 metres with a horizontal lateral of 2,407
metres. The well was successfully completed with a 30 stage
slickwater hybrid completion. The well has been flowing on clean-up
over the past 4.5 days, recovering approximately 21 percent of the
initial load frac water and is now shut-in to equip the well for
production. Over the past 4.5 days the well has flowed at an average
rate of approximately 8.9 mmcf/d of raw gas and approximately 800
bbls/d of wellhead condensate (90 bbls/mmcf of raw gas). Over the
last 24 hours the well has produced at an average rate of 8.8 mmcf/d
of raw gas and approximately 750 bbls/d of wellhead condensate (85
bbls/mmcf of raw gas), at a flowing pressure of approximately 530
psi. With a similar plant NGL yield of 36 bbls/mmcf of raw gas, total
production over this last 24 hour period was approximately 2,350
boe/d (45 percent NGL's). 
The Company is currently drilling its third horizontal Montney well
of the winter season in East Bigstone with a planned bottom hole
location at 16-23-60-23W5. The horizontal lateral is planned for a
total of 2,900 metres and will also be completed with the same 30
stage slickwater hybrid frac system. 
Delphi expects to commence drilling operations after spring break-up
on the previously announced farm-in lands to earn a 75 percent
interest in the Montney and Nordegg on the 32.5 section land block.
After earning, the Company will hold an average working interest of
85 percent in 78.5 sections of prospective Montney and Nordegg rights
in the Bigstone area. 
The Company's Montney production at East Bigstone was shut-in on
February 12, 2013 due to unscheduled pipeline repairs on a
third-party main gathering pipeline. The outage is estimated to last
until the first week of March. 
Delphi anticipates releasing its audited financial statements for the
year ended December 31, 2012 on March 20, 2013 and its Annual
Information Form by March 29, 2013, which will include all required
National Instrument 51-101 reserves disclosure. 
Certain financial and operating information included in this press
release for the quarter and year ended December 31, 2012, such as,
but not limited to, finding and development costs, production
information, net asset value calculations, are based on unaudited
financial results for the year ended December 31, 2012 and are
subject to the same limitations as discussed under forward-looking
statements outlined at the end of this release. These estimate
amounts may change upon completion of the audited financial
statements for the year ended December 31, 2012 and those changes may
be material. 
Delphi Energy is a Calgary-based company that explores, develops and
produces oil and natural gas in Western Canada. The Company is
managed by a proven technical team. Delphi trades on the Toronto
Stock Exchange under the symbol DEE. 
Forward-Looking Statements. This management discussion and analysis
contains forward-looking statements and forward-looking information
within the meaning of applicable securities laws. The use of any of
the words "expect", "anticipate", "continue", "estimate", may",
"will", "should", believe", "intends", "forecast", "plans",
"guidance" and similar expressions are intended to identify
forward-looking statements or information. 
More particularly and without limitation, this management discussion
and analysis contains forward looking statements and information
relating to the Company's risk management program, petroleum and
natural gas production, future funds from operations, capital
programs, commodity prices, costs and debt levels. The
forward-looking statements and information are based on certain key
expectations and assumptions made by Delphi, including expectations
and assumptions relating to prevailing commodity prices and exchange
rates, applicable royalty rates and tax laws, future well production
rates, the performance of existing wells, the success of drilling new
wells, the capital availability to undertake planned activities and
the availability and cost of labour and services. 
Although the Company believes that the expectations reflected in such
forward-looking statements and information are reasonable, it can
give no assurance that such expectations will prove to be correct.
Since forward-looking statements and information address future
events and conditions, by their very nature they involve inherent
risks and uncertainties. Actual results may differ materially from
those currently anticipated due to a number of factors and risks.
These include, but are not limited to, the risks associated with the
oil and gas industry in general such as operational risks in
development, exploration and production, delays or changes in plans
with respect to exploration or development projects or capital
expenditures, the uncertainty of estimates and projections relating
to production rates, costs and expenses, commodity price and exchange
rate fluctuations, marketing and transportation, environmental risks,
competition, the ability to access sufficient capital from internal
and external sources and changes in tax, royalty and environmental
legislation. Additional information on these and other factors that
could affect the Company's operations or financial results are
included in reports on file with the applicable securities regulatory
authorities and may be accessed through the SEDAR website
( The forward-looking statements and information
contained in this press release are made as of the date hereof for
the purpose of providing the readers with the Company's expectations
for the coming year. The forward-looking statements and information
may not be appropriate for other purposes. Delphi undertakes no
obligation to update publicly or revise any forward-looking
statements or information, whether as a result of new information,
future events or otherwise, unless so required by applicable
securities laws. 
Basis of Presentation. For the purpose of reporting production
information, reserves and calculating unit prices and costs, natural
gas volumes have been converted to a barrel of oil equivalent (boe)
using six thousand cubic feet equal to one barrel. A boe conversion
ratio of 6:1 is based upon an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead. This conversion conforms with the
Canadian Securities Administrators' National Instrument 51-101 when
boes are disclosed. Boes may be misleading, particularly if used in
As per CSA Staff Notice 51-327 initial test results and initial
production performance should be considered preliminary data and such
data is not necessarily indicative of long-term performance or of
ultimate recovery. 
Non-IFRS Measures. The release contains the terms "funds from
operations", "funds from operations per share", "net debt", "cash
operating costs" and "netbacks" which are not recognized measures
under IFRS. The Company uses these measures to help evaluate its
performance. Management considers netbacks an important measure as it
demonstrates its profitability relative to current commodity prices.
Management uses funds from operations to analyze performance and
considers it a key measure as it demonstrates the Company's ability
to generate the cash necessary to fund future capital investments and
to repay debt. Funds from operations is a non-IFRS measure and has
been defined by the Company as net earnings plus the add back of
non-cash items (depletion and depletion, accretion, stock-based
compensation, deferred income taxes and unrealized gain/(loss) on
financial instruments) and excludes the change in non-cash working
capital related to operating activities and expenditures on
decommissioning obligations. The Company also presents funds from
operations per share whereby amounts per share are calculated using
weighted average shares outstanding consistent with the calculation
of earnings per share. Delphi's determination of funds from
operations may not be comparable to that reported by other companies
nor should it be viewed as an alternative to cash flow from operating
activities, net earnings or other measures of financial performance
calculated in accordance with IFRS. The Company has defined net debt
as the sum of long term debt plus/minus working capital excluding the
current portion of deferred income taxes and fair value of financial
instruments. Net debt is used by management to monitor remaining
availability under its credit facilities. Cash operating costs have
been defined as the sum of operating expenses, transportation
expense, general and administrative expenses and cash finance costs.
Delphi Energy Corp.
David J. Reid
President & CEO
(403) 265-6171 
Delphi Energy Corp.
Brian P. Kohlhammer
Senior VP Finance & CFO
(403) 265-6171
(403) 265-6207 (FAX) 
Delphi Energy Corp.
300, 500 - 4 Avenue S.W.
Calgary, Alberta
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