New Zealand Energy Corp. ("NZEC" or the "Company") (TSX VENTURE:NZ)(OTCQX:NZERF)
has released the results of its fourth quarter and fiscal year ended December
31, 2013. Details of the Company's financial results are described in the
Audited Consolidated Financial Statements and Management's Discussion and
Analysis which, together with further details on the Company's operational
activities, are available on the Company's website at www.newzealandenergy.com
and on SEDAR at www.sedar.com. All amounts are in Canadian dollars unless
otherwise stated.




                NZEC will host a conference call May 1, 2014                
                            1-2pm PST (4-5pm EST)                           
                  North American toll-free: 1-800-319-4610                  
               International / Vancouver callers: 604-638-5340              



HIGHLIGHTS



--  Ten wells in production at year-end 2013 (2012: four wells) 
--  77,484 barrels of oil produced and 77,820 barrels of oil sold during
    2013 (2012: 162,444 and 162,077) 
--  Total recorded revenue of $10,662,879 (2012: $16,475,971) 
--  Significantly improved average field netback during second half of 2013
    to $60.34 per barrel (compared to $35.10 per barrel in first six months
    of 2013) 
--  Invested $37.7 million in resource properties, plant and equipment
    during 2013 
--  Completed acquisition of strategic midstream and exploration assets in
    the Taranaki Basin, recognizing a Gain on Acquisition of $1.4 million 
--  Increased 2P Reserves by 145% compared to year-end 2012, with an after
    tax net present value (10% discount) of $57.9 million 
--  Cumulative third-party revenue earned to date through Waihapa Production
    Station of $687,000 (net to NZEC) 
--  New arrangement with gas marketing counterparty is expected to commence
    May 5, 2014 and generate between NZ$250,000 and NZ$1 million revenue per
    year (net to NZEC) 
--  NZEC retracts its year-end 2014 production guidance 



Message from the Chief Executive Officer

As the CEO of NZEC, I am focused on the milestones we need to achieve in the
days, weeks and months ahead to ensure that our business can continue to grow.
Reviewing the year-end financial statements, however, has provided the
opportunity for me to reflect on the events that occurred during what was
certainly a transformative year for NZEC. 


NZEC started 2012 with four producing oil wells and an active exploration
program on its Eltham Permit, and the expectation of imminently closing the
acquisition of the TWN assets from Origin. The acquisition took much longer than
expected, but the opportunities and benefits this acquisition brought to the
Company far outweigh the challenges. NZEC ended 2013 with ten producing wells, a
145% increase to its 2P reserves, and a 50% interest in strategic midstream
infrastructure in the heart of the Taranaki Basin. In the first few months of
2014, NZEC has also brought two more wells online and anticipates near-term
production increases from additional wells.


Since closing the acquisition at the end of October 2013, NZEC moved quickly to
deliver on a number of milestones. The Company successfully reactivated oil
production from seven existing wells and confirmed that production can be
achieved from an uphole reservoir, following a successful uphole completion. In
addition, the Company delivered on its promise of realizing new business
opportunities through the Waihapa Production Station, which is now generating
revenue from third-party business opportunities.


I am pleased with our success and proud of the team's ability to be innovative
and nimble. I tasked the team with reviewing these new assets from every angle
and identifying opportunities to use the existing wells and infrastructure to
increase production. The team identified numerous production opportunities in
the due diligence period before NZEC closed the acquisition, and each of the
development activities to date has yielded oil production. The technical and
operations teams continue to review well logs, historical drilling records and
seismic data across the TWN Licenses and have identified additional
opportunities to advance existing wells to production. 


The Company's primary challenge, however, has been timing. Continued delays in
closing the acquisition resulted in delays to realizing production and cash flow
from the new assets. Likewise, the sequential development activities that NZEC
had planned for the assets were also pushed back. While NZEC was initially
optimistic that it could make up the time, the recent decision to defer drilling
of a new Tikorangi well made it clear that the Company's year-end production
guidance is no longer attainable, and the Company retracts its previously stated
production guidance. NZEC still expects to achieve that production target. NZEC
has great confidence in the assets and in the production potential from the
multiple drill-proven formations that underlie the Company's Taranaki permits.
All that's changed is the timing. NZEC is focused on responsible development of
its assets, looking for optimal production from each well and ensuring that we
fully understand both the assets and the impact of each development activity
before we move ahead to the next task.


For the remainder of 2014, NZEC will prioritize low-cost, low-risk opportunities
that are expected to bring near-term production and cash flow. Concurrently, the
Company continues to take significant steps to reduce overhead, consolidating
its three New Plymouth premises into one office and eliminating a number of
consulting and employment positions. NZEC's objective is to organically build up
working capital through internally-generated cash flow. Once the Company has
established a strong production and cash flow base, the Company can again look
to advancing higher-impact operations, such as drilling new wells. 


To ensure that NZEC can continue to advance its non-core assets, the Company is
actively seeking farm-in partners for its Eltham and Alton exploration permits
in the Taranaki Basin and also for its East Coast permits. Securing a farm-in
partner would allow the Company to expedite exploration of priority drill
targets, including the deeper high-impact Tikorangi and Kapuni targets, while
reducing NZEC's financial and technical risk. Establishing strong partnerships
has been one of the cornerstones of NZEC's success to date. The Company has
established strategic partnerships with L&M Energy and Westech Energy New
Zealand, and built a strong relationship with New Zealand Oil & Gas and also its
iwi partners in both the Taranaki and East Coast basins. 


NZEC's reputation as a responsible and entrepreneurial oil and gas developer has
allowed the Company to attract industry experts. I am very excited that David
Robinson will join the team on May 19th to assume the new position of Chief
Executive Officer of the Company's New Zealand business and also join NZEC's
Board of Directors. David brings considerable oil and gas insight to the Company
from a corporate, industry and regulatory perspective. His expertise and
enthusiasm will be invaluable as NZEC continues to execute its business and
development plans.


I believe NZEC has both the assets and the business plan required to build a
substantial oil and gas company. Progress has been slower than expected, but we
are indeed making progress, and I see many opportunities ahead. We have a core
team of highly qualified and experienced individuals who are focused and
committed to the success of this Company. I look forward to sharing the
Company's successes with our shareholders and community partners as our
development plans unfold in 2014.


FINANCIAL SNAPSHOT 



----------------------------------------------------------------------------
                         For the                                            
                         quarter   For the year  For the year  For the year 
                           ended          ended         ended         ended 
                    December 31,   December 31,  December 31,  December 31, 
                            2013           2013          2012          2011 
--------------------------------- ------------------------------------------
Production            16,790 bbl     77,484 bbl   162,444 bbl    11,623 bbl 
Sales                 13,968 bbl     77,820 bbl   162,077 bbl     9,567 bbl 
--------------------------------- ------------------------------------------
Price               115.77 $/bbl   109.09 $/bbl  106.71 $/bbl  106.83 $/bbl 
Production costs     43.39 $/bbl    58.73 $/bbl   31.57 $/bbl   23.44 $/bbl 
Royalties            10.53 $/bbl     5.98 $/bbl    5.06 $/bbl    4.96 $/bbl 
Field netback        61.84 $/bbl    44.38 $/bbl   70.08 $/bbl   78.43 $/bbl 
--------------------------------- ------------------------------------------
Revenue                4,108,911     10,662,879    16,475,971       974,517 
Pre-production                                                              
 recoveries                    -              -     2,449,231       950,440 
Total comprehensive                                                         
 loss                 (5,963,723)    (9,303,312)   (1,235,492)   (6,655,829)
Finance income                                                              
 (expense)               (30,804)       (97,598)      211,511       119,583 
Loss per share -                                                            
 basic and diluted         (0.06)         (0.12)        (0.03)        (0.08)
Current assets        15,147,197     15,147,197    49,137,637    19,293,345 
Total assets         116,782,687    116,782,687   116,059,939    31,152,804 
Total long-term                                                             
 liabilities           7,068,585      7,068,585     2,598,840       120,429 
Total liabilities     15,337,630     15,337,630    23,442,632     1,383,376 
Shareholders'                                                               
 equity              101,445,057    101,445,057    92,617,307    29,769,428 
----------------------------------------------------------------------------



Note: The abbreviation bbl means barrel or barrels of oil.

As at April 30, 2014, the Company had an estimated $2.7 million in working capital.

SIGNIFICANT DEVELOPMENTS

In the fourth quarter of 2013, NZEC completed the TWN Acquisition, assumed joint
control of the acquired assets and reactivated oil production in six wells
drilled by previous operators; booked additional reserves and resources related
to the TWN Acquisition; closed an oversubscribed private placement for gross
proceeds of $16.1 million; completed its acquisition of an 80% interest in the
Wairoa Permit; extended the exploration period for the Alton Permit and the
Eltham Permit by five years to September 2018; and relinquished the Ranui
Permit. 


Subsequent to year-end, NZEC advanced three additional wells to production on
the TWN Licenses and recommenced production from one well on the Eltham Permit.
The Company has also made a number of changes to its New Zealand senior
management team, released an updated reserve estimate and relinquished its
interest in the Manaia Permit.


Initial development plans for the TWN Licenses included drilling a crestal well
to access oil reserves attributed to the Tikorangi Formation. The TWN JA has
determined that the crestal well will not be drilled in 2014. Drilling the
Tikorangi crestal well was integral to NZEC achieving its year-end 2014
production guidance. With the Tikorangi well deferred, NZEC has made the
decision to retract is year-end 2014 production guidance, as previously
announced on August 6, 2013.


PROPERTY REVIEW 

Taranaki Basin

The Taranaki Basin is situated on the west coast of New Zealand's North Island
and is currently the country's only oil and gas producing basin, with total
production of approximately 130,000 barrels of oil equivalent per day ("boe/d")
from 18 fields. Within the Taranaki Basin, NZEC holds a 100% interest in the
Eltham Permit, a 65% interest in the Alton Permit with L&M, and a 50% interest
in the TWN Licenses and the TWN Assets with L&M. The Eltham Permit currently
covers 47,387 acres (191.8 km2), of which approximately 2,029 acres (24.4 km2)
is offshore. The Company has lodged an application with NZPAM to convert 939
acres (3.8 km2) of the Eltham Permit into a PMP. When approved, the Eltham
Permit acreage will be reduced by the size of the PMP. The Alton Permit covers
approximately 59,565 onshore acres (241 km2). The TWN Licenses cover
approximately 23,049 onshore acres (93 km2). 


NZEC is actively seeking farm-in partners for its Eltham and Alton permits, with
the intention that the farm-in partner would fund the drilling of high-priority
targets on the properties in return for an interest in the permits. 


The Taranaki Basin offers production potential from multiple prospective
formations, ranging from the Kapuni sandstones at a depth of approximately 4,000
metres, the Tikorangi limestones at approximately 3,000 metres, the Moki
sandstones at approximately 2,500 metres, and the shallower Mt. Messenger and
Urenui sandstones at approximately 2,000 metres. All of NZEC's production to
date is from the Tikorangi and Mt. Messenger formations.


Production and Processing Revenue

At the date of this MD&A, the Company had advanced 12 wells to production: four
wells on the Eltham Permit and eight wells on the TWN Licenses. The Company's
oil production during March 2014 averaged 233 bbl/d net to NZEC (not including
production from the Waihapa-8 well). On March 29, 2014 the Waihapa-8 well
commenced production, on April 12, 2014 the Toko-2B well recommenced production
following installation of high-volume lift, and on April 17, 2014 the Waihapa-2
well commenced production following a successful uphole completion. Production
during April 2014 averaged 228 bbl/d net to NZEC. Production from Toko-2B,
Ngaere-2 and Ngaere-3 is combined into one single pipe that goes through the
B-train separator at the Waihapa Production Station. Ngaere-2 and Ngaere-3 were
taken offline on April 12, 2014 to allow for full evaluation of Toko-2B. In
addition, the Copper Moki-3 well remains shut-in awaiting installation of a new
pump later in Q2-2014. Details regarding the Company's efforts to increase
production from existing wells and bring new wells into production are available
in the Outlook section below.


TWN Licenses

The TWN JA has identified two opportunities for low-cost, near-term production
on the TWN Licenses: reactivating oil production from the Tikorangi and Mt.
Messenger formations in existing wells that were produced historically, and
recompleting existing wells uphole in shallower formations that have not been
produced. At the date of this MD&A, the TWN JA had advanced eight wells to
production for a total of 43,594 bbl produced since closing of the TWN
Acquisition (21,797 bbl net to NZEC), with cumulative pre-tax oil sales net to
NZEC of approximately $2,330,664 (net results of operations are discussed under
Results of Operations). The wells produce light approx. 41 degrees API oil that
is delivered by pipeline to the Waihapa Production Station and then piped to the
Shell-operated Omata tank farm, where it is sold at Brent pricing less standard
Shell costs.


Following closing of the TWN Acquisition, the TWN JA immediately proceeded with
the work required to reactivate oil production from the Tikorangi Formation in
six wells drilled by previous operators. On December 2, 2013, NZEC announced
that all six wells had been reactivated and were flowing into the Waihapa
Production Station. In March 2014, the TWN JA also reactivated oil production
from the Mt. Messenger Formation in a well that had been drilled and produced
from the Mt. Messenger Formation by a previous operator (Waihapa-8).


The TWN JA continues to evaluate and optimize production from the reactivated
wells. As part of the optimization process, in April 2014, the TWN JA installed
high-volume lift ("ESP") on one of the reactivated wells (Toko-2B). The ESP was
operated initially using a portable generator, which limited the pumping
capacity and did not draw down fluid levels in the well. The TWN JA is
connecting the Toko-2B high-volume lift to a permanent power source and will
gradually increase the pumping rate. The ESP is capable of pumping up to 10,000
barrels of total fluid per day.


A number of wells on the TWN Permits, with previous production from the
Tikorangi Formation, have uphole completion potential in the shallower Mt.
Messenger Formation. The TWN JA has recompleted one well uphole in the Mt.
Messenger Formation (Waihapa-2) and achieved production from that well in April
2014. This successful recompletion confirms that production can be achieved from
an uphole reservoir. The TWN JA has identified three more wells with uphole
completion potential, and will continue to evaluate these opportunities. One
additional well offers production potential from both the Tikorangi and Mt.
Messenger formations. The TWN JA is focusing first on reactivating production
from the Tikorangi Formation, but will proceed with an uphole completion in the
Mt. Messenger Formation if appropriate. 


The TWN JA continues to identify opportunities to generate revenue from the
Waihapa Production Station and associated infrastructure. Third-party revenue
from the Waihapa Production Station since closing the TWN Acquisition totals
approximately NZ $687,000 net to NZEC. In addition, during February 2014, the
TWN JA entered into an agreement with a gas marketing counterparty to transport
gas along a section of the TAW gas pipeline for a term of four years with a
five-year right of renewal. The arrangement is expected to generate between
NZ$250,000 and NZ$1 million revenue per year (net to NZEC). First gas is
expected to flow on May 5, 2014.


Eltham Permit 

To date the Company has drilled ten exploration wells on the Eltham Permit. Four
have been advanced to production. At the date of this MD&A, the Company has
produced approximately 279,842 bbl from its Eltham Permit wells (including oil
produced during testing), with cumulative pre-tax oil sales from inception of
approximately $31.2 million (net results of operations are discussed under
Results of Operations). Of the remaining six wells, one well (Copper Moki-4)
made an oil discovery in the Urenui Formation and has been shut-in pending
additional economic analysis and evaluation of artificial lift options. One well
(Arakamu-2) made an oil discovery in the Mt. Messenger Formation and has been
shut-in pending evaluation of artificial lift options. One well (Wairere-1A) was
drilled to the Mt. Messenger Formation and encountered hydrocarbon shows, with
completion pending. Waitapu-1 is shut-in pending further testing or sidetrack to
an alternate target and Arakamu-1A, a Moki Formation well, is suspending pending
further evaluation. Only one well, Wairere-1, failed to encounter hydrocarbons
and was immediately sidetracked.


All of the Eltham Permit wells produce light approx. 41 degrees API oil from the
Mt. Messenger Formation. Oil is trucked to the Shell-operated Omata tank farm
and sold at Brent pricing less standard Shell costs. During January 2014, NZEC
began delivering natural gas produced from wells on the Copper Moki site through
a pipeline to the Waihapa Production Station, where it is blended with gas
produced from the TWN Licenses and used by the TWN Partnership to lift the TWN
JA reactivated wells and run the Waihapa Production Station compressors. Using
internally generated gas for these activities, rather than purchasing it, has
significantly reduced operating costs at the Waihapa Production Station and
brought modest natural gas revenue to the Company.


East Coast Basin

The East Coast Basin of New Zealand's North Island hosts two prospective oil
shale formations, the Waipawa and Whangai, which are believed to be the source
of more than 300 oil and gas seeps. Within the East Coast Basin, NZEC holds a
100% interest in the Castlepoint Permit, which covers approximately 551,042
onshore acres (2,230 km2), and a 100% interest in the East Cape Permit which
covers approximately 1,048,406 onshore acres (4,243 km2) on the northeast tip of
the North Island. In addition, NZEC holds an 80% working interest in the Wairoa
Permit, which covers approximately 267,862 onshore acres (1,084 km2) south of
the East Cape Permit. NZEC is the operator of all three permits. 


The Company has completed the coring of two test holes and collected 35 line km
of 2D seismic data on the Castlepoint Permit. The Wairoa Permit has been
actively explored for many years, with extensive 2D seismic data across the
permit and log data from more than 16 wells drilled on the property. Members of
NZEC's geological and geophysical team understand the property well and had
previously provided extensive consulting services to previous permit holders,
assisting with seismic acquisition and interpretation, well-site geology and
regional prospectivity evaluation. In addition, NZEC's team assisted with
permitting and land access agreements and worked extensively with local district
council, local service providers, land owners and iwi groups, allowing the team
to establish an excellent relationship with local communities. During Q1-2013
the Company completed a 50 km 2D seismic program on the Wairoa Permit.


OUTLOOK 

Taranaki Basin

Completing the acquisition of the TWN Licenses and TWN Assets has transformed
NZEC into a fully integrated upstream/midstream company. Having a 50% interest
in a full-cycle production facility and associated infrastructure should allow
NZEC to optimize the development of all of its Taranaki Basin permits. As NZEC
continues to explore its Taranaki Basin property portfolio, the Company will
focus on developing targets that are close to the Waihapa Production Station and
associated pipelines, allowing for accelerated and cost effective tie-in of both
oil and gas production. 


The majority of the Company's near-term production and exploration efforts will
be focused on the TWN Licenses, where existing wells offer low-cost, near-term
production potential. The TWN JA has already reactivated production from seven
wells and advanced one uphole completion to production. In addition, the TWN JA
expects to achieve an increase to production from one well following
installation of high-volume lift, and is considering installing high-volume lift
in additional wells. The TWN JA continues to review well logs, historical
drilling records and seismic data across the TWN Licenses to identify additional
opportunities to advance existing wells to production. The TWN JA has identified
production potential from both the Tikorangi and Mt. Messenger formations in
additional existing wells, and will continue to evaluate these opportunities.
Reactivations and uphole completions are significantly less expensive and faster
than drilling new wells, and economic discoveries can often be tied in to the
Waihapa Production Station using existing oil and gas gathering pipelines. 


During 2014, the Company plans to drill a new exploration well on the Alton
Permit. The current work program for the Alton Permit requires the Company to
drill an exploration well by June 22, 2014. The Company has applied to NZPAM to
extend the deadline by three months to accommodate environmental consulting
work. The Company has identified a drill target in the Mt. Messenger Formation
and has initiated the community engagement and technical assessments required to
obtain land access consents and permits. In addition, new exploration targets in
the Mt. Messenger, Tikorangi and Kapuni formations on the TWN Licenses and the
Eltham and Alton permits could be drilled in future exploration programs. NZEC
is actively seeking farm-in partnerships to advance both its Eltham and Alton
permits.


The Company announced its initial development plans for the TWN Licenses and
other permits in the Taranaki Basin on August 6, 2013. NZEC and the TWN JA
continue to review development plans for the TWN Licenses and have identified
new production opportunities in existing wells. As a result, timing of a number
of a planned exploration and development activities has shifted. The TWN JA will
prioritize low-cost, low-risk opportunities that are expected to bring near-term
production and cash flow, and will defer higher-cost, higher-risk operations
until the TWN JA has established a strong production and cash flow base. 


NZEC believes that optimization efforts can increase production from existing
wells. The TWN JA is connecting the Toko-2B high-volume lift to a permanent
power source and will gradually increase the pumping rate. The ESP is capable of
pumping in excess of 10,000 barrels of total fluid per day. Pumping rates are
being gradually increased at the Waihapa-2 well to maximize production. The
Waihapa-8 well is currently being produced using an existing gas lift system
that was installed by the previous operator, but the TWN JA may consider
installing more sophisticated artificial lift. In addition, the Copper Moki-3
well on the Eltham Permit is expected to resume production in Q2-2014 following
installation of a new pump. The TWN JA has identified four additional production
opportunities in existing wells on the TWN Licenses: three uphole completions in
the Mt. Messenger Formation and one well that offers production potential from
both a Tikorangi reactivation and a Mt. Messenger uphole completion. The TWN JA
will continue to evaluate these opportunities with the objective of advancing
these wells to production. 


NZEC remains focused on reducing costs while increasing production from existing
wells with the objective of organically building up working capital through
internally-generated cash flow. In addition, NZEC is actively seeking farm-in
partners for its Eltham and Alton permits, with the intention that the farm-in
partner would fund the drilling of high-priority targets on the properties in
return for an interest in the permits. 


The Company's ability to execute its exploration and development activities is
contingent on its financial capacity. Based on available working capital, as
well as forecasted positive net cash flow from operations, management has
estimated that the Company has sufficient working capital to meet short-term
operating requirements. However, since these estimates rely on certain
development activities that are still underway as at the date of this report,
there are no assurances that these activities will be successful, or that the
Company will be able to attain sufficient profitable operations from those
activities. In light of the reliance on successful completion of ongoing
development activities, there is significant doubt about the Company's ability
to continue as a going concern.


The Company is considering a number of options to increase its financial
capacity (including increasing cash flow from oil production, credit facilities,
joint arrangements, commercial arrangements or other financing alternatives) in
order to meet all required and planned capital expenditures for the next 12
months. 


East Coast Basin 

The Company is actively seeking a farm-in partner for its East Coast permits, to
participate in and fund exploration and development in the East Coast Basin in
return for an interest in the permits. 


NZEC used information from two stratigraphic test holes and a 2D seismic survey
to focus its exploration plans for the Castlepoint Permit. The current work
program requires the Company to drill an exploration well by May 23, 2014, but
the Company expects NZPAM to grant a six-month extension to this deadline. The
Company has identified its preferred drill location and has initiated the
community engagement and technical assessments required to obtain land access
and resource consents.


The current work program for the Wairoa Permit requires the Company to drill an
exploration well by July 2, 2014, but the Company has applied to NZPAM for a
six-month extension to this deadline. The Company has identified the preferred
drill location and has initiated the community engagement and technical
assessments required to obtain land access and resource consents. 


The Company anticipates completing fieldwork and geochemical studies on the East
Cape Permit in 2014.


SUMMARY OF QUARTERLY RESULTS



----------------------------------------------------------------------------
                          2013-Q4       2013-Q3       2013-Q2       2013-Q1 
                                $             $             $             $ 
----------------------------------------------------------------------------
                                                                            
Total assets          116,782,687   105,313,813   127,318,182   129,545,992 
Exploration and                                                             
 evaluation assets     51,500,037    55,859,632    52,357,470    49,610,922 
Property, plant and                                                         
 equipment             49,169,997    26,621,043    26,135,651    25,793,089 
Working capital         6,878,152     4,748,797     9,517,742    17,533,636 
Revenues                4,108,911     1,519,010     2,109,700     2,925,258 
Accumulated deficit   (35,099,834)  (27,292,947)  (24,616,053)  (22,386,089)
Total comprehensive                                                         
 income (loss)         (5,963,723)    1,347,788    (6,000,775)    1,313,397 
Basic (loss)                                                                
 earnings per share         (0.06)        (0.02)        (0.02)        (0.02)
Diluted (loss)                                                              
 earnings per share         (0.06)        (0.02)        (0.02)        (0.02)
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
                          2012-Q4       2012-Q3       2012-Q2       2012-Q1 
                                $             $             $             $ 
----------------------------------------------------------------------------
                                                                            
Total assets          116,059,939    98,882,087    98,814,102    96,979,923 
Exploration and                                                             
 evaluation assets     37,379,726    26,377,188    25,373,718    12,103,712 
Property, plant and                                                         
 equipment             23,867,758    16,293,123     8,674,152     8,150,802 
Working capital        28,293,845    45,204,695    53,844,035    70,401,191 
Revenues                2,948,041     3,708,254     5,910,993     3,908,683 
Accumulated deficit   (19,992,243)  (17,804,045)  (15,613,594)  (16,548,180)
Total comprehensive                                                         
 income (loss)         (1,333,805)   (2,018,634)    1,317,915       799,032 
Basic (loss)                                                                
 earnings per share         (0.02)        (0.02)         0.01          0.00 
Diluted (loss)                                                              
 earnings per share         (0.02)        (0.02)         0.01          0.00 
----------------------------------------------------------------------------



RESULTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2013

Revenue

During the year ended December 31, 2013, the Company produced 77,484 (2012:
162,444) bbl and sold 77,820 (2012: 162,077) bbl for total oil sales of
$8,489,319 (2012: $17,295,853), or $109.09 (2012: $106.71) per bbl. Total
recorded gross production revenue was $8,023,973 (2012: $16,475,971), which
accounted for royalties of $465,346 (2012: $819,882), or $5.98 (2012: $5.06) per
bbl sold. 


During the year ended December 31, 2013, the Company recorded sales from
purchased oil of $664,168 (2012: $nil) and purchased condensate of $1,506,068
(2012: $nil). The Company also received $468,671 (2012: $nil) of processing
revenue from the Company's interest in the Waihapa Production Station.


Total recorded revenue during the year ended December 31, 2013 was $10,662,879
(2012: $2,948,042), which is accounted for net of royalties of $465,347 (2012:
$161,164).


Expenses and Other Items

Production costs during the year ended December 31, 2013 totalled $4,570,294
(2012: $5,116,059), or $58.73 (2012: $31.57) per bbl sold. Included in total
production costs are all site-related expenditures, including applicable
equipment rental fees, site services, overheads and labour; transportation and
storage costs including trucking, testing, tank storage, processing and
handling; and port dues as incurred prior to the sale of oil. Other costs of
$2,170,236 relate to purchased oil and condensates which were on-sold by the
Company to a third party. The Company continues to see the positive effect on
production costs from installation of surface facilities as reflected in reduced
production costs related to the Copper Moki site since June 2013. 


Depreciation costs incurred during the year ended December 31, 2013 totalled
$3,193,785 (2012: $4,103,405), or $41.04 (2012: $25.32) per bbl sold.
Depreciation is calculated using the unit-of-production method by reference to
the ratio of production in the period to the related total proved and probable
reserves of oil and natural gas, taking into account estimated future
development costs necessary to access those reserves. The increase in per bbl
depreciation during the period ended December 31, 2013 is reflective of the
additional wells (and therefore additional development costs associated with
such wells) that achieved commercial production since Q3-2012.


Stock-based compensation for the year ended December 31, 2013 totalled $685,257
compared to $1,594,780 during the same period in 2012. The decrease in
stock-based compensation corresponds to fewer stock options granted and the
reversal of stock-based compensation related to employees who left the Company
during the period. 


General and administrative expenses for the year ended December 31, 2013
totalled $7,197,024 compared to $5,896,949 incurred in the same period in fiscal
2012. The increase in general and administrative costs corresponds to salary
increases related to new employees, as the Company prepared for the expansion of
operations following the TWN Acquisition.


Transaction costs for the year ended December 31, 2013 totalled $1,823,243
compared to $1,161,657 incurred in the same period in fiscal 2012. The
transaction costs incurred during the period include legal and professional fees
incurred in relation to the TWN Acquisition.


Net finance expense for the year ended December 31, 2013 totalled $97,598
compared to net finance income of $211,551 in the same period in fiscal 2012.
Finance expense relates to interest payable on the Company's operating line of
credit, and accretion of the Company's asset retirement obligations, presented
net of interest earned on the Company's cash and cash-equivalent balances held
in treasury and on term deposits.


Foreign exchange loss for the year ended December 31, 2013 amounted to $452,176
compared to a $1,895,845 loss realized in the same period of fiscal 2012. The
decrease in foreign exchange gain loss is a result of the weakening of the New
Zealand dollar against the US dollar, during a period in which the Company's
subsidiaries (which have a New Zealand dollar functional currency) held US
dollar denominated working capital in anticipation of closing the TWN
Acquisition.


Impairment - During the year, the Company made the decision to focus its East
Coast exploration efforts on the Wairoa, Castlepoint and East Cape permits and
relinquished the Ranui Permit. As a result, the Company wrote off $6,708,960 of
exploration and evaluation assets previously capitalized to the permit. An
additional $275,484 was written down to determine the fair value of the land and
building held for sale.


Total Comprehensive Loss 

Total comprehensive loss for the year ended December 31, 2013 totalled
$9,303,312 after taking into account a gain on the exchange difference on
translation of foreign currency of $5,804,279 which compared to total
comprehensive loss for the year ended December 31, 2012 of $1,235,492.


Based on a weighted average shares outstanding balance of 127,319,719, the
Company realized a $0.12 basic and diluted loss per share for the year ended
December 31, 2013. During the year ended December 31, 2012, based on a weighted
average shares outstanding balance of 117,131,297 the Company realized a $0.03
basic and diluted loss per share. 


NEW STOCK OPTIONS

NZEC has issued a total of 800,000 incentive stock options to an officer and a
consultant of the Company. The options expire five years from the date of grant
and vest at a rate of 25% every six months for a 24-month period. The options
will have an exercise price of $0.45 per share.


On behalf of the Board of Directors

John Proust, Chief Executive Officer & Director 

About New Zealand Energy Corp.

NZEC is an oil and natural gas company engaged in the production, development
and exploration of petroleum and natural gas assets in New Zealand. NZEC's
property portfolio collectively covers approximately 1.91 million acres of
conventional and unconventional prospects in the Taranaki Basin and East Coast
Basin of New Zealand's North Island. The Company's management team has extensive
experience exploring and developing oil and natural gas fields in New Zealand
and Canada, and takes a multi-disciplinary approach to value creation with a
track record of successful discoveries. NZEC plans to add shareholder value by
executing a technically disciplined exploration and development program focused
on the onshore and offshore oil and natural gas resources in the politically and
fiscally stable country of New Zealand. NZEC is listed on the TSX Venture
Exchange under the symbol NZ and on the OTCQX International under the symbol
NZERF. More information is available at www.newzealandenergy.com or by emailing
info@newzealandenergy.com.


Neither the TSX Venture Exchange nor its Regulation Services Provider (as such
term is defined in the policies of the TSX Venture Exchange) accepts
responsibility for the adequacy or accuracy of this release. 


FORWARD-LOOKING INFORMATION

This document contains certain forward-looking information and forward-looking
statements within the meaning of applicable securities legislation (collectively
"forward-looking statements"). The use of the word "expectation", "will",
"expect", "continue", "continuing", "could", "should", "further", "pending",
"anticipates", "offers", "intend", "objective", "become", "potential", "pursue",
"look forward", "increasing" and similar expressions are intended to identify
forward-looking statements. 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
including, without limitation, the speculative nature of exploration, appraisal
and development of oil and natural gas properties; uncertainties associated with
estimating oil and natural gas reserves and resources; uncertainties in both
daily and long-term production rates and resulting cash flow; volatility in
market prices for oil and natural gas; changes in the cost of operations,
including costs of extracting and delivering oil and natural gas to market, that
affect potential profitability of oil and natural gas exploration and
production; the need to obtain various approvals before exploring and producing
oil and natural gas resources; exploration hazards and risks inherent in oil and
natural gas exploration; operating hazards and risks inherent in oil and natural
gas operations; the Company's ability to generate sufficient cash flow from
production to fund future development activities; market conditions that prevent
the Company from raising the funds necessary for exploration and development on
acceptable terms or at all; global financial market events that cause
significant volatility in commodity prices; unexpected costs or liabilities for
environmental matters; competition for, among other things, capital,
acquisitions of resources, skilled personnel, and access to equipment and
services required for exploration, development and production; changes in
exchange rates, laws of New Zealand or laws of Canada affecting foreign trade,
taxation and investment; failure to realize the anticipated benefits of
acquisitions; and other factors as disclosed in documents released by NZEC as
part of its continuous disclosure obligations. 


Such forward-looking statements should not be unduly relied upon. The Company
believes the expectations reflected in those forward-looking statements are
reasonable, but no assurance can be given that these expectations will prove to
be correct. Actual results could differ materially from those anticipated in
these forward-looking statements. The forward-looking statements contained in
the document are expressly qualified by this cautionary statement. These
statements speak only as of the date of this document and the Company does not
undertake to update any forward-looking statements that are contained in this
document, except in accordance with applicable securities laws.


CAUTIONARY NOTE REGARDING RESERVE ESTIMATES

The oil and gas reserves calculations and income projections were estimated in
accordance with the Canadian Oil and Gas Evaluation Handbook ("COGEH") and
National Instrument 51-101 ("NI 51-101"). The term barrels of oil equivalent
("boe") may be misleading, particularly if used in isolation. A boe conversion
ratio of six Mcf: one bbl was used by NZEC. This conversion ratio is based on an
energy equivalency conversion method primarily applicable at the burner tip and
does not represent a value equivalency at the wellhead. Reserves are 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 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. Revenue projections presented are based
in part on forecasts of market prices, current exchange rates, inflation, market
demand and government policy which are subject to uncertainties and may in
future differ materially from the forecasts above. Present values of future net
revenues do not necessarily represent the fair market value of the reserves
evaluated. The report also contains forward-looking statements including
expectations of future production and capital expenditures. Information
concerning reserves may also be deemed to be forward looking as estimates imply
that the reserves described can be profitably produced in the future. These
statements are based on current expectations that involve a number of risks and
uncertainties, which could cause the actual results to differ from those
anticipated. 


FOR FURTHER INFORMATION PLEASE CONTACT: 
New Zealand Energy Corp.
John Proust
Chief Executive Officer & Director
North American toll-free: 1-855-630-8997


New Zealand Energy Corp.
Rhylin Bailie
Vice President Communications & Investor Relations
North American toll-free: 1-855-630-8997
info@newzealandenergy.com
www.newzealandenergy.com

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