Dune Energy, Inc. Reports Year-End 2013 Proved Reserves Of 15.5 MMboe, Up 3% From Year-End 2012

 Dune Energy, Inc. Reports Year-End 2013 Proved Reserves Of 15.5 MMboe, Up 3%
                              From Year-End 2012

PR Newswire

HOUSTON, Feb. 4, 2014

HOUSTON, Feb. 4, 2014 /PRNewswire/ -- Dune Energy, Inc. (OTCBB:DUNR) today
reported year-end 2013 proved oil and gas reserves of 7,163 Mbo and 50.1 Bcf
of gas or 15,519 MBoe. Oil volumes increased 578 Mbo or 9% and gas volumes
decreased 0.5 Bcf over year-end 2012 reported reserves. PV@10% value of these
reserves, as calculated in accordance with applicable financial and reporting
standards of the SEC, totaled $311.7 million. This was a $51.1 million
increase or 19.6% above the year-end 2012 PV@10% value of $260.6 million.

A third party, independent reserve report was done as of June 30, 2013 by
DeGolyer & MacNaughton. The year-end 2013 reserve report was completed by
Dune. The prices used at year-end 2013 were $93.39 per Bbl and $3.66 per
Mmbtu.

Year-End 2012 vs. Year-End 2013

The following table compares proved, probable and possible reserve amounts for
year-end 2012 and year-end 2013.

                             MMboe         MMboe
Reserve Category             Year-End 2012 Year-End 2013 Increase
Proved Developed (PDP, PDNP) 8.4           8.2           (2%)
Proved Undeveloped (PUD)     6.6           7.3           11%
Total Proved                 15.0          15.5          3%
Probable/Possible            4.9           13.3          171%
Grand Total                  19.9          28.8          94%

The following table compares year-end 2011 reserves with year-end 2013
reserves. Dune underwent a complete financial restructuring at year-end 2011
and the table below reflects activity since the restructuring.

                             MMboe         MMboe
Reserve Category             Year-End 2011 Year-End 2013 Increase
Proved Developed (PDP, PDNP) 8.6           8.2           (5%)
Proved Undeveloped (PUD)     4.6           7.3           59%
Total Proved                 13.2          15.5          17%
Probable/Possible            1.7           13.3          682%
Grand Total                  14.9          28.8          93%

As seen below, from year-end 2011 through year-end 2013, we have invested
$77.5 million of new capital (excluding ARO), produced 1.63 MMboe, and added
3.91 MMboe, which resulted in a Finding and Development Cost of $19.81/Boe.
Production Replacement was 240% during this 24 month period. Year-end 2013
financial and reserve information has not yet been audited.

Reserve Reconciliation             MMboe
Year-End 2011 Proved Reserves      13.24
24 Months Production               <1.63>
Additions/Revisions                3.91
Year-End 2013 Proved Reserves      15.52
Investment (MM$)                   77.46
Finding and Development Cost $/Boe 19.81

Listed below is the distribution of reserves by major field.

Major Field Breakout by Reserves Year-End 2013 (MMboe)

Field             Proved Probable/Possible Total
Leeville          5.7    12.4              18.2
Garden Island Bay 1.7    .06               2.3
Bateman Lake      1.6    .02               1.8
Chocolate Bayou   0.7    0.0               0.7
Other             5.8    0.1               5.8
Total             15.5   13.4              28.8

2013/2014 Production Volumes

In total, 2013 production was 436 Mbo and 1,913 MMcfe or 755 MBoe. On a daily
basis this averaged 2,068 Boe/day and 58% of the production was oil.
Production for the 1st quarter of 2013 averaged 1,801 Boe/day reflecting the
company having just commenced a drilling program at our Leeville field.
Second quarter production averaged 2,606 Boe/day primarily driven by
production increases at our Leeville field. June production peaked at 2,733
Boe/day. Third and fourth quarter production averaged 2,047 Boe/day and 1,817
Boe/day respectively. Production at Leeville, our largest producing field,
was negatively impacted by a non-operated pipeline shut in of approximately 60
days. Additionally, the field operator at the Leeville field changed on
October 1, 2013, and during the transition time from the old to the new
operator production declined due to minimal field maintenance activity.
Normal field maintenance was resumed in December along with the initiation of
another shallow drilling program. Dune completed drilling the Wieting #31 in
the Chocolate Bayou field in the 3rd quarter and commenced production as
previously reported. The reservoir encountered in this wellbore was very
limited and the zone watered out by the end of the 4th quarter. It is
anticipated that the well will be sidetracked in 2014 to encounter the full
reservoir which is included in our year-end reserve report as a PUD location.
Normal declines occurred in our other fields during the third and fourth
quarters.

With new drilling activity in our Leeville field coming on production during
the first quarter of 2014we anticipate first quarter production to be between
1,900 and 2,200 Boe/day. Depending on capital availability during the quarter
we have several additional drilling and workover opportunities ready to
commence in our other fields. January field level production averaged
approximately 1,900 Boe/day with 35% of this coming from the Leeville field.

Upside Potential

Over and above the 15.5 MMBoe of proved reserves, the company has identified
and additional unrisked51 MMboe of probable, possible, and exploratory
reserves. These projects are defined with recent fully processed 3-D seismic
data and within our acreage positions. The majority of this upside potential
is within our Garden Island Bay field. Capital required to explore and
develop these opportunities is significantly above our current cash flows.
During 2014 we anticipate seeking joint venture partners or outside capitalto
allow the company to participate in drilling these identified upside
opportunities.

2014 Budget

The Company is in the process of developing a risk-adjusted budget that will
fund some exploratory projects in our Garden Island Bay field in addition to a
second development drilling program at our Leeville Field. In addition, we
anticipate redrilling, to approximately 20,200 feet, the deep exploratory well
in the Leeville field that was junked and abandoned last year. Insurance
proceeds will cover substantially all of our cost of drilling this well back
to approximately 19,000 feet where the prior well was lost. This risked
capital budget will be adapted to the constraints of our available capital,
which currently is limited to free cash flow and availability under our
revolver. The revolver availability is currently $47.5 million with $29
million drawn and $2 million of standby letters of credit issued. However,
actual availability is not based solely on the undrawn/unused portion of the
revolver. Borrowing capacity is further limited by the quarterly Debt/EBITDAX
of less than 5.0 to 1.0 for year end 2013 and the first quarter of 2014. The
Debt/EBITDAX covenant will be 4.0 to 1.0 commencing at the end of the second
quarter and going forward in 2014.

James A. Watt, President and CEO of the company stated, "Post the
restructuring late in 2011, we have increased reserves and defined significant
upside opportunities. The potential for organic growth far exceeds our
current cash flow and availability under our revolver. We will continue to
carefully monitor our capital program to achieve maximum production from our
asset base while staying within the constraints of our credit agreements. We
will evaluate potential transactions that can enhance our balance sheet, and
allow for the capital investments necessary to develop the opportunities
within our asset base."

Click here for more information:
http://www.duneenergy.com/news.html?b=1683&1=1

FORWARD-LOOKING STATEMENTS: This document includes forward-looking statements.
Forward-looking statements include, but are not limited to, statements
concerning estimates of expected drilling and development wells and associated
costs, statements relating to estimates of, and increases in, production, cash
flows and values, statements relating to the continued advancement of Dune
Energy, Inc.'s projects and other statements which are not historical facts.
When used in this document, the words such as "could," "plan," "estimate,"
"expect," "intend," "may," "potential," "should," and similar expressions are
forward-looking statements. Although Dune Energy, Inc. believes that its
expectations reflected in these forward-looking statements are reasonable,
such statements involve risks and uncertainties and no assurance can be given
that actual results will be consistent with these forward-looking statements.
Important factors that could cause actual results to differ from these
forward-looking statements include the potential that the Company's projects
will experience technological and mechanical problems, geological conditions
in the reservoir may not result in commercial levels of oil and gas
production, changes in product prices and other risks disclosed in Dune's
Annual report on Form 10-K filed with the U.S. Securities and Exchange
Commission.

Investor Contact:
Steven J. Craig
Sr. Vice President Investor Relations and Administration
713-229-6300

SOURCE Dune Energy, Inc.
 
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