NuLoch Resources Year-End 2009 Financials and 2010 Guidance

NuLoch Resources Inc. (TSX VENTURE:NLR.A)(TSX VENTURE:NLR.B) advises that it has
filed its audited annual financial statements as at December 31, 2009 and 2008
and for the years then ended along with the associated Management Discussion and
Analysis at www.sedar.com. The Annual General and Special Meeting of
Shareholders will be held on May 26, 2010 at 10:00 am at the Westin Calgary, 320
4th Avenue S.W., Calgary.


Production averaged 576 boe/d in 2009 and, currently, is in excess of 1,000
boe/d. Monetary amounts are presented in Canadian dollars.


2009 Accomplishments

Production increase

Increased exit production 36% to average 708 boe/d in Q4 2009 compared to 520
boe/d in Q4 2008. Production reached 810 boe/d in January 2010;


Oil production weighting

Moved to 55% oil production weighting in Q4 2009 compared to 36% in year-ago period;

Resource acquisitions

Total undeveloped lands increased from 32,000 net acres at the end of 2008 to
98,000 at December 31, 2009. Acquired significant undeveloped acreage to hold
56,000 net acres at Tableland, Saskatchewan and Divide County, North Dakota that
is prospective in the Bakken and Three Forks Sanish Formations (further expanded
to 65,000 net acres with the Burke County acquisition in January 2010);


Corporate acquisition

Acquired Wilderness Energy Corp. in an all-share transaction that added 200
boe/d and tax losses of $21.6 million;


Reserve additions

Proved and probable reserves of petroleum and natural gas increased by 49% to
end 2009 at 3,455 Mboe. The associated value of $40.1 million (before tax, 10%
discounted cash flow) is a 34% increase. All-in finding, development and
acquisition costs in the year were $26.56 per boe (three year average $32.81 per
boe); 


Market capitalization

NuLoch's market capitalization increased from $8.1 million on December 31, 2008
to finish 2009 at $75.7 million;


Equity financing

A $26.8 million bought deal equity financing was completed in October 2009 and
the Company was debt-free at December 31, 2009; and


Production target

Targeting 2010 exit rate of 1,800 boe/d (83% crude oil) based on a 2010 capital
program of $40 - $50 million.




HIGHLIGHTS                                                                  
                                             Periods ended December 31,     
                                    ----------------------------------------
                                          Three months           Years      
                                    ---------------------  -----------------
                                          2009     2008       2009     2008 
                                    ---------------------  -----------------
OPERATING                                                                   
----------------------------------------------------------------------------
Production - daily                                                          
 average                                                                    
 Oil and NGL             (bbls/d)          392      189        239      195 
 Natural gas             (Mcf/d)         1,899    1,982      2,020    1,959 
 Combined oil equivalent (boe/d)(1)        708      520        576      522 
Average sales prices                                                        
 Oil and NGL             ($/bbl)         73.26    58.66      65.43    97.42 
 Natural gas             ($/Mcf)          4.57     6.87       4.31     8.36 
 Combined oil equivalent ($/boe)         52.77    47.56      42.31    67.84 
                                                                            
FINANCIAL                                                                   
($ thousands except per share                                               
 amounts)                                                                   
----------------------------------------------------------------------------
Petroleum and natural gas revenue        3,436    2,273      8,888   12,959 
                                                                            
Funds flow from operations(2)            1,282      911      2,957    6,565 
 Per share - basic                        0.02     0.02       0.06     0.19 
 Per share - diluted                      0.02     0.02       0.06     0.19 
                                                                            
Net earnings (loss)(3)                   1,238     (266)     1,884    1,373 
 Per share - basic                        0.02    (0.01)      0.04     0.04 
 Per share - diluted                      0.02    (0.01)      0.04     0.04 
                                                                            
Working capital (deficiency)                                                
 - end of period                           374   (4,414)       374   (4,414)
Line of credit(4)                        7,000    9,000      7,000    9,000 
                                                                            
Capital expenditures using cash         19,561    1,455     20,879   15,995 
                                                                            
COMMON SHARES                                                               
(thousands)                                                                 
----------------------------------------------------------------------------
Class A, end of period(5)               78,288   30,780     78,288   30,780 
Class B, end of period                     653      653        653      653 
Employee options, end of period          7,415    2,618      7,415    2,618 
Underwriter options, end of period       1,106        -      1,106        - 
Basic, weighted average combined        71,535   37,305     49,031   35,037 
Diluted, weighted average               77,407   37,305     49,735   35,322 
----------------------------------------------------------------------------
                                                                            
(1) Six Mcf of natural gas is considered equivalent to 1 barrel of oil (see
    Advisories).                                                            
(2) Cash flow from operations before changes in non-cash operating          
    working capital (see Advisories).                                       
(3) In Q3 2009 the Company recorded a $2,281,000 gain from an               
    extraordinary item.                                                     
(4) In February 2010, the line of credit was increased to $8.5 million.     
(5) Currently at 95,448,538.                                                



Outlook

NuLoch has focused on developing light oil prospects over the past several years
to reduce its exposure to weak natural gas prices. This past year was one of
transition where the Company positioned itself to take advantage of light oil
resource plays in the Bakken and Three Forks Sanish formations in the Williston
Basin. The equity markets have reacted favourably to this strategic initiative
and NuLoch raised a total $49.8 million through equity financings in October
2009 and February 2010.


A year ago, proved and probable reserves of oil accounted for 9% of NuLoch's
total reserves on a barrel of oil equivalent basis; at December 31, 2009, oil
has moved to 38% of the total. Proved undeveloped (PUD) oil reserves have been
assigned on some of the Company's 10% working interest acreage in North Dakota.
In March 2010 the Company increased its operations in North Dakota through the
acquisition of 8,500 net acres of undeveloped land and 15 barrels of oil per day
in Burke County. The purchase price, established effective January 21, 2010, was
approximately US$3,100,000.


At Tableland, one Three Forks Sanish horizontal well (1.0 net) was drilled and
completed in late 2009 and came on-stream in February 2010 with a 30 day average
rate of 205 barrels of oil per day. That well has been assigned proved light oil
reserves of 130 Mbbl and proved plus probable reserves of 180 Mbbl based on
analogous wells located nearby in Divide County, North Dakota. Given the early
stage of development in Canada, there are no proved undeveloped locations
assigned to any of the Company's 34,200 net acres at Tableland. Since year end,
NuLoch has drilled four (2.8 net) offsetting Three Forks Sanish wells where one
well has been equipped for production and three wells await completion. A fifth
well (0.7 net) located approximately six miles east awaits completion in the
Middle Bakken Formation. NuLoch has licenced 3 more wells (2.1 net) at Tableland
and, if results from these eight wells are as encouraging as those of the first
well, then the Company will consider an acceleration of the program in the
second half of 2010.


While the Company has had good access to drilling rigs on both sides of the
border over the past five months, we are seeing a tightening in the availability
of fracture stimulation services. This may lead to higher costs and production
delays. This early stage of development presents challenges when setting targets
for production and reserves growth. Currently, NuLoch is assuming each Three
Forks Sanish well in Saskatchewan will average 150 barrels of oil per day in its
first month and decline exponentially to half that rate after the first year. In
North Dakota, where more production history is available, the starting rate is
assumed to be 225 bbls/d with similar decline characteristics. A 2010 capital
expenditure budget of $40 - $50 million leads to a target exit rate for 2010 of
1,800 boe/d (83% crude oil).


Advisories

Use of Barrels of Oil Equivalent (boe)

Disclosure provided herein in respect of boe units may be misleading,
particularly if used in isolation. A boe conversion ratio of 6 Mcf of natural
gas to 1 bbl of crude oil is based on an energy equivalency conversion method
primarily applicable at the burner tip and may not represent a value equivalency
at the wellhead.


Use of Estimates in Reserves

The net present value of future net revenue attributable to the Company's
reserves is stated without provision for interest costs and general and
administrative costs, but after providing for estimated royalties, production
costs, development costs, other income, future capital expenditures, and well
abandonment costs for only those wells assigned reserves by AJM. The estimates
of reserves and future net revenue for individual properties may not reflect the
same confidence level as estimates of reserves and future net revenue for all
properties, due to effects of aggregation. Actual recoveries may be greater than
or less than the estimates provided herein and there is no guarantee that the
estimated reserves will be recovered. It should not be assumed that the values
of future net revenue attributable to the Company's reserves represent the fair
market value of those reserves.


Calculation of Finding and Development Costs

Finding costs per boe of reserves added are a rough measure of the average per
unit costs of finding and developing petroleum and natural gas reserves.


The aggregate of the 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 total finding and development costs
related to reserve additions for that year.


Non-GAAP Measurement - Funds Flow

Funds flow from operations, calculated as cash flow from operating activities
before changes in non-cash working capital, is used by the Company as a key
measure of performance. Funds flow from operations does not have a standardized
meaning prescribed by Canadian GAAP and therefore may not be comparable with the
calculation of similar measures for other companies. Funds flow from operations
as presented is not intended to represent operating profits for the period, nor
should it be viewed as an alternative to cash provided by operating activities,
net earnings or other measures of financial performance calculated in accordance
with GAAP. Many of the Company's peers in the oil and natural gas industry use
the same definition and, therefore, disclosure herein enhances comparability
with those peers. Funds flow from operations per share is calculated using the
same share bases which are used in the determination of earnings per share.


Forward-Looking Statements

Certain statements in this document or incorporated herein by reference
constitute "forward-looking statements". These forward-looking statements can
generally be identified as such because of the context of the statements,
including words indicating that the Company "believes", "anticipates",
"expects", "plans" or words of a similar nature. Such forward-looking statements
involve known and unknown risks, uncertainties and other factors which may cause
the actual results, performance or achievements of the Company, or industry
results, to be materially different from any future results, performance or
achievements expressed or implied by such forward-looking statements. Such
factors include, among others, the following: general economic and business
conditions which will, among other things, impact demand for and market prices
of the Company's products; industry capacity; the ability of the Company to
implement its business strategy, including exploration and development
activities; the ability of the Company to complete its capital programs;
successful negotiations with bankers and other third parties; the success of
exploration and development activities; production levels; government
regulations and the expenditures required to comply with them (especially safety
and environmental laws and regulations); asset retirement obligations; and other
circumstances affecting revenues and expenses.