NuLoch Resources Inc.
TSX VENTURE : NLR.A
TSX VENTURE : NLR.B

NuLoch Resources Inc.

April 16, 2007 06:55 ET

NuLoch Resources Announces Year-End 2006 Results and Reserves

CALGARY, ALBERTA--(CCNMatthews - April 16, 2007) - NuLoch Resources Inc. (TSX VENTURE:NLR.A) (TSX VENTURE:NLR.B) was incorporated on May 13, 2005 and commenced operations on July 1, 2005. Production averaged 284 boe/d in 2006 and, currently, is approximately 300 boe/d.



HIGHLIGHTS 2006 2005(1)
----------------------------------------------------------------------------

OPERATING
----------------------------------------------------------------------------

Production - daily average
Oil and NGL bbls/d 5 3
Natural gas mcf/d 1,672 172
Combined oil equivalent boe/d(2) 284 32

Average sales prices
Oil and NGL $/bbl 58.38 58.46
Natural gas $/mcf 6.29 11.42
Combined oil equivalent $/boe 38.14 67.78


FINANCIAL
----------------------------------------------------------------------------

Petroleum and natural gas revenue $ 3,955,154 $ 386,387

Funds flow from operations(3) 1,356,770 (33,140)
Per share - basic 0.08 -
Per share - diluted 0.08 -

Net earnings (loss) (225,230) (897,140)
Per share - basic (0.01) (0.10)
Per share - diluted (0.01) (0.10)

Working capital (deficiency) (2,270,974) (3,407,474)
Line of credit 5,500,000 4,000,000

Capital expenditures $ 11,511,404 $ 11,089,106


COMMON SHARES
----------------------------------------------------------------------------

Class A, end of period 15,196,995 7,712,695
Class B, end of period 652,500 652,500
Options, end of period 822,500 822,500
Basic, weighted average combined 16,302,937 9,063,864
----------------------------------------------------------------------------

(1) Six months from inception of operations to December 31, 2005.
(2) Six mcf of natural gas is considered equivalent to 1 barrel of oil.
(3) Cash flow from operations before changes in non-cash operating working
capital.


MESSAGE TO SHAREHOLDERS

December 31, 2006 marks the first 18 months of operations for NuLoch. From inception to that date, the Company has added over 2.2 million boe of proved and probable reserves - all through the drill bit. Production averaged 284 boe/d in 2006 and generated cash flow of $1.4 million.

For the industry, 2006 was a year of records: record land prices; record labour shortages; record drilling costs. The record prices for natural gas were achieved a year earlier, in 2005, declined sharply in early 2006 and remaining weak for most of the year. This mismatch of revenues and costs was a call-to-action for NuLoch.

In response, NuLoch took deliberate action, limiting its fourth quarter capital expenditures to $0.4 million. We concluded that preservation of capital and strength in the balance sheet were more important than adding production at any cost. As a result, the 2006 exit rate was 283 boe per day. While the proved plus probable reserve value stood at $23.4 million at year end, the net working capital deficiency was kept to less than $2.3 million. The financial flexibility resulting from our capital discipline may allow NuLoch to take advantage of industry opportunities this year, while many other juniors are in discussions with their bankers. Nevertheless, NuLoch still faces challenges.

The Company plans to invest $7 million to $10 million in its capital program in 2007. A significant portion of this budget will be devoted to exploration projects in satisfaction of the remaining $3.8 million CEE commitment made to flow-through investors in 2006. If recent strength in natural gas prices persists, a portion of the budget will go towards re-completions and new drilling for Second White Specks shallow gas at Enchant, Alberta - a planned project that was deferred in 2006. The balance of the activity is likely to be generated internally with opportunities obtained through farm-ins.

NuLoch's three-phase strategy remains unchanged and it is worth reiterating here.

Phase I

Underpin the Company with a low-risk, long-life natural gas reserve base. We have a bullish outlook for natural gas over the long-term.

Phase II

Develop medium depth natural gas. These wells are expected to provide good initial production rates over the first year, generating excellent cash-flow and rate of return. Subsequently they are expected to follow the typical Mannville production curve, declining into stable, lower-rate, long-life reserves.

Phase III

Provide balance with oil. Crude oil and natural gas prices do not necessarily move in unison. We are actively seeking appropriate oil prospects with a view to developing reserves over the next 12 to 18 months.

The Phase I shallow gas project, commenced late in 2005, fully met our expectations and will provide a solid production base for years to come. We have 25 additional locations left to be drilled that can be used to stabilize or add to production as required. NuLoch's 2006 Phase II and III programs did not meet our expectations, encountering cost overruns, delays and lower than anticipated production rates. However, the light oil prospect at Balsam has recently been returned to production at rates in excess of 125 b/d of oil (40 b/d net) while the Enchant Phase II wells currently contribute 40 boe/d net. An additional 25 boe/d of Enchant production will resume after break-up.

Outlook

Following the defensive period of late 2006, NuLoch intends to resume growing in 2007. The Federal government's October 31, 2006 announcement of proposed tax measures with respect to income trusts has brought uncertainty - and perhaps opportunity - to the junior oil and natural gas sector as trusts adjust their business plans. NuLoch can benefit from this if under-explored land, currently tied-up in the trusts, is made available for farm-in.

This year should bring reductions in the costs to buy land and drill wells as the industry continues to slow from its record-breaking pace. Later in the year, natural gas prices may enjoy additional support when it becomes evident that ongoing reservoir declines are not being fully offset through new drilling.

Our 2007 drilling plans include three firm locations (1.8 net) in the first quarter and at least four additional net wells over the balance of the year. Drilling of up to 25 wells on the Enchant shallow gas project, which would be triggered by a renewed strength in natural gas prices, would be incremental to this program.

EXTRACTS FROM MANAGEMENT'S DISCUSSION AND ANALYSIS

NuLoch Resources Inc. (NuLoch or the Company) was incorporated under the laws of the Province of Alberta on May 13, 2005. No operations were undertaken in the period from incorporation until the end of the second quarter on June 30, 2005.



Overview

Production
----------------------------------------------------------------------------
Q1 Q2 Q3 Q4 Annual
------- ------- ------- ------- -------
2006
Production - daily average
Oil and NGL (bbls/d) - 1 11 9 5
Natural gas (mcf/d) 1,713 1,766 1,590 1,622 1,672
Total oil equivalent (boe/d) 286 295 276 279 284

2005
Production - daily average
Oil and NGL (bbls/d) - - 1 4 3
Natural gas (mcf/d) - - 76 268 172
Total oil equivalent (boe/d) - - 14 49 32


Selected Financial Information
($ thousands, except per share information)
----------------------------------------------------------------------------
Q1 Q2 Q3 Q4 Annual
------- ------- ------- ------- -------
2006
Petroleum and natural gas revenue 1,101 931 875 1,048 3,955
Funds flow from operations 427 142 288 500 1,357
Per share - basic 0.03 0.01 0.02 0.03 0.08
- diluted 0.03 0.01 0.02 0.03 0.08
Net earnings (loss) (7) (39) (156) (23) (225)
Per share - basic - - (0.01) - (0.01)
- diluted - - (0.01) - (0.01)
Total assets, end of period 13,195 18,260 20,885 20,925 20,925
Working capital (deficiency)
end of period (825) 148 (4,345) (2,271) (2,271)

2005
Petroleum and natural gas revenue - - 66 320 386
Funds flow from operations - - (133) 100 (33)
Per share - basic - - (0.01) 0.01 -
- diluted - - (0.01) 0.01 -
Net earnings (loss) - - (1,318) 421 (897)
Per share - basic - - (0.12) 0.04 (0.10)
- diluted - - (0.12) 0.03 (0.10)
Total assets, end of period - - 6,712 14,233 14,233
Working capital (deficiency),
end of period - - 5,975 (3,407) (3,407)


During the fourth quarter of 2005, the Company drilled 42 shallow gas wells at Enchant, Alberta and nine of them produced during December. Completion operations and tie-ins continued through the first quarter of 2006 and all 38 wells capable of production were on-stream at March 31, 2006. These wells accounted for virtually all of the Company's production during the first nine months of 2006. During the second half of 2006, four (2.4 net) natural gas wells at Enchant and two (0.8 net) oil wells at Balsam were placed on-stream that provided 21 percent of the Company's sales volumes in the fourth quarter.

Capital Expenditures

A total of $11.5 million was expended in 2006. Eight (4.5 net) wells were drilled in the year. Three (1.5 net) wells were drilled at Balsam and five (3.0 net) were drilled in southern Alberta at Enchant.



Capital Expenditures
Periods ended December 31, 2006 and 2005
----------------------------------------------------------------------------
2006 2005
------------ ------------

Land $ 555,543 $ -
Drilling and completions 7,952,709 8,397,305
Equipment 1,810,321 2,000,059
Geoscience 508,434 -
Acquisition of petroleum and
natural gas properties - 324,993
Capitalized G&A 667,919 246,797
Administrative assets 16,478 119,952
------------ ------------
$11,511,404 $11,089,106
------------ ------------
------------ ------------

Wells Drilled
Periods ended December 31, 2006 and 2005
----------------------------------------------------------------------------
Natural Success
Oil gas Suspended Dry Total ratio
------- ------- --------- ------- ------- --------

2006
Gross 1 4 1 2 8
Net 0.3 2.4 0.5 1.3 4.5 60%

2005
Gross - 39 - 4 43
Net - 38.9 - 4.0 42.9 91%

Reserves of Petroleum and Natural Gas

NuLoch retained AJM Petroleum Consultants (AJM) to conduct the evaluation of
the Company's petroleum and natural gas reserves as at December 31, 2006.
AJM's report was compiled pursuant to the guidelines of National Instrument
51-101.

Company Gross Reserves as at December 31, 2006
----------------------------------------------------------------------------
Light &
Medium Natural
Oil Gas NGL Total
(mbbls) (mmcf) (mbbls) (mboe)
------- ------- ------- -------
Proved producing 87 3,774 8 723
Proved non-producing - 233 3 42
Proved undeveloped - 4,109 - 685
------- ------- ------- -------
Total proved 87 8,116 11 1,450
Probable 44 3,996 2 712
------- ------- ------- -------
Total proved and probable 131 12,112 13 2,162
------- ------- ------- -------
------- ------- ------- -------

Forecast Net Revenue as at December 31, 2006
----------------------------------------------------------------------------
Before Income Tax
-------------------------------
$000s, discounted at 0% 5% 10% 15%
------- ------- ------- -------

Proved producing 17,753 14,219 11,891 10,261
Proved non-producing 1,339 1,100 925 793
Proved undeveloped 10,755 6,327 3,554 1,740
------- ------- ------- -------
Total proved 29,847 21,646 16,370 12,794
Probable 23,105 11,918 7,074 4,675
------- ------- ------- -------
Total proved and probable 52,952 33,564 23,444 17,469
------- ------- ------- -------
------- ------- ------- -------

After Income Tax
-------------------------------
$000s, discounted at 0% 5% 10% 15%
------- ------- ------- -------

Proved producing 16,416 13,389 11,351 9,895
Proved non-producing 977 818 702 614
Proved undeveloped 7,682 4,318 2,168 742
------- ------- ------- -------
Total proved 25,075 18,525 14,221 11,251
Probable 16,949 8,752 5,201 3,443
------- ------- ------- -------
Total proved and probable 42,024 27,277 19,422 14,694
------- ------- ------- -------
------- ------- ------- -------

Future prices used in the forecast of net revenue are based on those
estimated by AJM as at December 31, 2006. The first five years of forecast
prices are summarized below:


Five-Year Forecast of Future Prices
----------------------------------------------------------------------------
Oil Oil Natural gas
WTI Edmonton AECO average
Year ($US/bbl) ($CDN/bbl) ($CDN/mcf)
---- ------------- ------------- -------------

2007 65.00 72.85 7.40
2008 69.35 77.75 8.00
2009 70.75 79.35 7.90
2010 69.00 77.30 8.00
2011 67.10 75.15 8.25


Reserve Reconciliation (Company Working Interest)
----------------------------------------------------------------------------
Light &
Medium Natural
Oil Gas NGL Total
(mbbls) (mmcf) (mbbls) (mboe)
------- ------- ------- -------
Proved
December 31, 2005 - 7,928 - 1,321
Operational additions 88 839 12 240
Acquisition additions - - - -
Revisions - (41) - (7)
Production (1) (610) (1) (104)
------- ------- ------- -------
December 31, 2006 87 8,116 11 1,450

Probable
December 31, 2005 - 3,964 - 661
Operational additions 44 152 2 71
Acquisition additions - - - -
Revisions - (120) - (20)
Production - - - -
------- ------- ------- -------
December 31, 2006 44 3,996 2 712

Proved plus probable
December 31, 2005 - 11,892 - 1,982
Operational additions 132 991 14 311
Acquisition additions - - - -
Revisions - (161) - (27)
Production (1) (610) (1) (104)
------- ------- ------- -------
December 31, 2006 131 12,112 13 2,162
------- ------- ------- -------
------- ------- ------- -------


Finding, development and acquisition (FD&A) costs

FD&A costs are derived by dividing all costs incurred in exploratory, development and acquisition activities in a period by the proved and proved plus probable reserves added in that period. These FD&A costs are further adjusted to include any future development activity estimated to be required to place the reported reserves on production.



FD&A Costs
For the period from inception to December 31, 2006
----------------------------------------------------------------------------
Since
2006 inception
------------- -------------

Additions to property and equipment $ 11,552,404 $ 23,034,510

Add (deduct):
Change in asset retirement obligations (20,000) (413,000)
Office equipment (16,478) (136,430)
Change in future development costs (1,997,500) 8,439,500
------------- -------------
$ 9,518,426 $ 30,924,580
------------- -------------
------------- -------------

FD&A costs per boe - Proved $ 40.90 $ 19.83
- Proved plus probable $ 33.50 $ 13.61


Revenue

The Company's production averaged 279 boe/d in the fourth quarter of 2006 compared to 49 boe/d in the corresponding period of 2005. Virtually all of this production was natural gas and associated liquids.



Production, Prices and Revenue
----------------------------------------------------------------------------
2006 2005
------------------------------- ---------------
Q4 Q3 Q2 Q1 Q4 Q3
------- ------- ------- ------- ------- -------

Production - daily average
Oil and NGL (bbls/d) 9 11 1 - 4 1
Natural gas (mcf/d) 1,622 1,590 1,766 1,713 268 76
Combined oil
equivalent (boe/d) 279 276 295 286 49 14

Average sales prices
Oil and NGL ($/bbl) 50.69 65.25 51.94 62.82 59.57 53.85
Natural gas ($/mcf) 6.74 5.53 5.76 7.13 12.16 8.84

Gross petroleum and natural
gas revenue ($ thousands) 1,048 875 931 1,101 320 66


The Company's production operations commenced on July 1, 2005. In 2005, production consisted of two (1.4 net) natural gas wells at Shouldice, Alberta and, starting in early December, the first nine wells of the Company's 42-well shallow gas program at Enchant, Alberta. Rates from Shouldice have declined to nominal amounts while the Enchant shallow gas property achieved a peak production rate of approximately 500 boe/d (3 mmcf/d) when all 38 successful wells were tied-in during the first quarter of 2006. In the fourth quarter, the combined net production rate from these 38 wells was 220 boe/d with an average of 200 boe/d expected in 2007.

During the second half of 2006, two (0.8 net) Kiskatinaw oil wells at Balsam were placed on-stream. Pressure information on one well (0.5 net) indicates it has a limited reservoir and has been suspended. The other well produced at restricted rates until tie-in of the associated natural gas was completed early in 2007. Full production resumed in February 2007 with an initial net rate of approximately 40 boe/d.

At Enchant, the Company completed four (2.4 net) natural gas wells drilled in 2006 and equipped another natural gas well (0.6 net) on lands earned through drilling. Four of the wells commenced production in 2006 while tie-in of the fifth well was delayed until early 2007. These five Enchant wells are currently producing natural gas and associated liquids at a combined net rate of approximately 40 boe/d with 25 boe/d shut-in over break-up.

The Company anticipates continuing strength in the markets for oil and natural gas through 2007. Natural gas is expected to be the primary focus of the Company's development program in 2007. Natural gas pricing was under pressure throughout 2006 as the market considered the historically high levels of product in storage, and declined sharply from its historical record highs in the fourth quarter of 2005. Prices began to improve with the new "gas year" commencing on November 1. A cold winter in North America and high draws from storage in February 2007 provided further support to the market. Oil prices weakened in the fourth quarter of 2006 but strengthened again in the first quarter of 2007.

Royalties

NuLoch's Second White Specks (SWS) natural gas program at Enchant is a farm-in project on Crown mineral leases that provides for the payment of overriding royalties to the farmors based on 15 percent of gross revenue. The average combined Crown and other royalty rate for the Company, net of ARTC, was 18 percent in 2006. ARTC totalled $88,367 in 2006, being 25 percent of eligible Crown royalties payable. The government of Alberta terminated the ARTC program effective January 1, 2007. The effective royalty rate excluding ARTC was 20 percent during 2006.



Royalties
Periods ended December 31, 2006 and 2005
----------------------------------------------------------------------------
2006 2005
----------------- -----------------
Amount % Amount %
------------ ---- ------------ ----
Petroleum and natural gas revenue $ 3,955,154 100 $ 386,387 100

Crown royalties $ 356,665 9 $ 15,319 4
ARTC (88,367) (2) (3,830) (1)
Freehold royalties 20,280 1 39,104 10
Overriding royalties 409,676 10 29,986 8
------------ ---- ------------ ----
Royalties, net of ARTC $ 698,254 18 $ 80,579 21
------------ ---- ------------ ----
------------ ---- ------------ ----


Operating Expense

Operating expense can vary significantly depending on such factors as production rates, reservoir quality, water content and available infrastructure. The Company's target is to maintain average operating expenses below $10.00 per boe of production. In 2006 operating expenses including transportation averaged $9.18 per boe, compared to $7.49 per boe for the last six months of 2005.

Interest Expense

Interest expense was nil in 2005. At times during 2006 the Company drew upon its credit facility with a Canadian chartered bank and incurred interest totalling $74,623. The balance outstanding under the credit facility at December 31, 2006 was $2,320,513 with interest payable at the bank's prime rate plus 0.5 percent per annum.

In 2006 the Company incurred Federal Part XII.6 tax totalling $68,267 - characterized as interest - with respect to $4.9 million of renouncements pursuant to flow-through common shares issued in 2005. Expenditure commitments with respect to those renouncements were met in full during 2006. Additional issuances of flow-through shares were made in 2006 and Part XII.6 is expected to be incurred in 2007 in respect of certain of the associated renunciations.

General and Administrative (G&A) Expense

In 2006, the Company had seven employees at its leased head office in Calgary and used external consultants on an as-needed basis to assist with the regular operation of the business. Office lease obligations are approximately $125,000 per annum with expiry in November 2008.



G&A
Periods ended December 31, 2006 and 2005
----------------------------------------------------------------------------
2006 2005
------------ ------------

Gross overhead costs $ 1,493,534 $ 602,432
Overhead recoveries (21,575) -
Stock-based compensation 52,000 26,000
Amounts capitalized (667,919) (246,797)
------------ ------------
$ 856,040 $ 381,635
------------ ------------
------------ ------------


The average net rate for G&A in 2006 was $8.26 per boe produced. The rate for 2005 is not meaningful given the Company's early stage of operations and insignificant production. The Company may see significant increases in gross G&A in 2007 as the scope of operations expands, but achieve a decrease in G&A costs per unit of production as production continues to increase as planned.

Depletion and Depreciation

The rate of depletion and depreciation with respect to petroleum and natural gas properties, excluding administrative assets, was $17.91 per boe produced. This rate is consistent with finding, development and acquisition costs of $16.13 per boe proved reported in respect of 2005, which relate primarily to the shallow gas reserves at Enchant, Alberta. FD&A costs per proved boe added in 2006 were higher and resulted in higher rates of depletion per boe produced.

Income Taxes

The Company does not expect to incur any current income or capital taxes in 2006. In the first quarter of 2006, the Company renounced $7,250,000 in eligible Canadian Exploration Expense with respect to flow-through shares issued in 2005. The income tax effect of the renouncement, being $2,440,000, was recorded in the first quarter of 2006 as a reduction in share capital and increase in future income tax liability. Additional flow-through shares totalling $7,251,515 were issued in 2006 with renouncement of Canadian Exploration Expense made in the first quarter of 2007. The income tax effect of the renouncement will be recorded at that time.

Reductions in federal and provincial income tax rates in respect of 2006 through 2010 were substantively enacted during the three months ended June 30, 2006. Accordingly, a reduction in the Company's future tax liability in the amount of $187,000 was recorded in that period.

Funds Flow and Net Loss

In 2005, the Company was in the early stages of developing its oil and natural gas production business. As such, funds flow from operations was negative for the six months ended December 31, 2005 primarily because the limited amount of net production revenue did not cover G&A expenses.

Funds flow from operations was positive in 2006 as production from the Enchant SWS shallow natural gas project contributed substantial revenue. Funds flow from operations totalled $1,356,770 in the year.

The Company incurred a net loss in 2006 totalling $225,230 on net revenues of $3,276,335.

Liquidity and Capital Resources

The amount of credit available under the Company's demand revolving operating facility with a Canadian chartered bank was increased to $5,500,000 in October, 2006. The borrowing base is expected to be re-evaluated by the bank in the second quarter of 2007 based on forecasts of the Company's reserves, production and cash flows.

On February 22, 2006 the Company issued, pursuant to a private placement, 3,050,000 Class A common shares at $1.65 per share for gross proceeds of $5,032,500.

On June 29, 2006 the Company issued 2,703,500 flow-through Class A common shares at $1.85 per share for gross proceeds of $5,001,475. A further 1,730,800 flow-through Class A common shares were issued on December 12, 2006 at $1.30 per share for gross proceeds of $2,250,040. Early in 2007, the Company renounced these amounts of tax deductions in the form of Canadian Exploration Expense to shareholders effective December 31, 2006 and has a commitment to incur these qualifying resource expenditures prior to December 31, 2007. As at December 31, 2006, approximately $2,400,000 of qualifying expenditures had been incurred.

The balance of the Company's expenditure commitment with respect to $7,250,000 of flow-through shares issued in 2005 was satisfied during the third quarter of 2006.

The Company's capital program was established at $13.7 million for 2006 while actual expenditures were approximately $11.5 million. Cash provided by operating activities is budgeted to provide a significant portion of the funding for the on-going capital program. In light of natural gas price declines during 2006 and the resulting effect on cash flow, certain projects were postponed by the Company. The Company is encouraged by the recent strengthening in Canadian natural gas markets and will proceed with its capital program as financial resources allow.

The Company proposes to invest $7 million to $10 million in its 2007 capital program which should include seven net wells. During 2007 oil is budgeted to average US$65.00 per barrel WTI and natural gas at AECO is budgeted to average C$7.40 per mcf. The Company's target exit production rate for 2007 of 500 boe/d, with an average of 400 boe/d for the year (2006 - 284 boe/d), has potential to yield funds flow from operations of approximately $2.5 million.

A shortfall in available funds may be satisfied with bank borrowings or further equity issues if appropriate. If these or other sources of funding are insufficient, or cannot be obtained with acceptable terms, then prudent reductions in the capital program may be warranted.

Related Parties

A director of the Company is a lawyer whose firm provides legal counsel to the Company at market rates. During 2006 amounts totalled $84,797 (2005 - $52,176).

Outstanding Share Data

The Class A and Class B common shares of the Company trade on the TSX Venture Exchange under the symbol NLR.A and NLR.B, respectively. As of the date of this MD&A there are 15,196,995 Class A common shares and 652,500 Class B common shares outstanding. There are 822,500 options to purchase Class A common shares outstanding.



Fourth Quarter 2006

2006 2005
----------------------- -----------------------
$000 $/boe $000 $/boe
------- --------------- ------- ---------------
Q4 Q4 Annual Q4 Q4 Annual
------- ------- ------- ------- ------- -------
Revenue:
Gross petroleum and
natural gas 1,048 40.79 38.14 320 71.89 67.78

Crown royalties (11) (0.44) (3.44) (15) (3.44) (2.69)
ARTC 2 0.08 0.85 4 0.86 0.67
Freehold royalties (5) (0.21) (0.19) (30) (6.62) (6.86)
Overriding royalties (61) (2.37) (3.95) (30) (6.74) (5.26)
------- ------- ------- ------- ------- -------
(75) (2.94) (6.73) (71) (15.94) (14.14)
Interest and other - - 0.19 33 7.44 10.42
------- ------- ------- ------- ------- -------
973 37.85 31.60 282 63.39 64.06
Expenses:
Operating 266 10.35 9.18 31 6.83 7.49
General and administrative 160 6.22 8.26 164 36.95 66.94
Interest 39 1.50 1.38 - - -
Depletion and depreciation 536 20.85 18.22 79 17.74 219.26
Asset retirement accretion 11 0.43 0.35 2 0.45 0.53
Future income tax reduction (16) (0.62) (3.62) (415) (93.24) (72.79)
------- ------- ------- ------- ------- -------
Net earnings (loss) (23) (0.88) (2.17) 421 94.66 (157.37)
------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- -------


EXTRACTS OF FINANCIAL STATEMENTS

Balance Sheets

As at December 31, 2006 2005
------------- -------------
Assets

Current assets:
Cash and cash equivalents $ - $ 2,705,240
Accounts receivable 887,466 737,968
Prepaid expenses and other assets 142,796 2,847
------------- -------------
1,030,262 3,446,055

Property and equipment (note 3) 19,894,510 10,232,106
Future income tax asset (note 7) - 555,000
------------- -------------
$ 20,924,772 $ 14,233,161
------------- -------------
------------- -------------

Liabilities and Shareholders' Equity

Current liabilities:
Accounts payable and accrued liabilities $ 980,723 $ 6,853,529
Bank loan (note 6) 2,320,513 -
------------- -------------
3,301,236 6,853,529

Asset retirement obligations (note 5) 452,000 396,000
Future income tax liability (note 7) 1,197,000 -

Shareholders' equity:
Share capital (note 8) 17,018,906 7,854,772
Contributed surplus (note 8(d)) 78,000 26,000
Deficit (1,122,370) (897,140)
------------- -------------
15,974,536 6,983,632

Commitment (note 11)
------------- -------------
$ 20,924,772 $ 14,233,161
------------- -------------
------------- -------------

Statements of Operations and Deficit

Period from
May 13, 2005
Year ended to
December 31, December 31,
2006 2005
------------- -------------
Revenue:
Petroleum and natural gas $ 3,955,154 $ 386,387
Royalties, net of
Alberta Royalty Tax Credit (698,254) (80,579)
Interest 19,435 59,392
------------- -------------
3,276,335 365,200

Expenses:
Operating 951,635 42,705
General and administrative (note 3) 856,040 381,635
Interest 142,890 -
Depletion and depreciation 1,890,000 1,250,000
Asset retirement accretion (note 5) 36,000 3,000
------------- -------------
3,876,565 1,677,340

------------- -------------
Loss before income taxes (600,230) (1,312,140)

Future income tax reduction (note 7) 375,000 415,000
------------- -------------
Net loss (225,230) (897,140)

Deficit, beginning of period (897,140) -
------------- -------------
Deficit, end of period $ (1,122,370) $ (897,140)
------------- -------------
------------- -------------

Net loss per share (note 8(e)):

Basic and diluted $ (0.01) $ (0.10)
------------- -------------
------------- -------------


Statements of Cash Flows

Period from
May 13, 2005
Year ended to
December 31, December 31,
2006 2005
------------- -------------

Cash provided by (used in):

Operating:
Net loss $ (225,230) $ (897,140)
Items not involving cash:
Future income tax reduction (375,000) (415,000)
Depletion and depreciation 1,890,000 1,250,000
Asset retirement accretion 36,000 3,000
Stock-based compensation 52,000 26,000
Asset retirement expenditures (21,000) -
------------- -------------
1,356,770 (33,140)
Change in non-cash
operating working capital 11,577 (99,265)
------------- -------------
1,368,347 (132,405)

Financing:
Issue of share capital,
net of issue costs 11,291,134 7,281,535
Increase in bank loan 2,320,513 -
Change in non-cash
financing working capital 33,198 -
------------- -------------
13,644,845 7,281,535

Investing:
Property and equipment (11,511,404) (10,655,869)
Change in non-cash
investing working capital (6,207,028) 6,211,979
------------- -------------
(17,718,432) (4,443,890)

------------- -------------
Increase (decrease) in cash and
cash equivalents (2,705,240) 2,705,240

Cash and cash equivalents,
beginning of period 2,705,240 -
------------- -------------
Cash and cash equivalents,
end of period $ - $ 2,705,240
------------- -------------
------------- -------------
Supplemental cash flow information (note 12)


EXTRACTS OF NOTES TO THE FINANCIAL STATEMENTS

Year ended December 31, 2006 and period from inception on May 13, 2005 to December 31, 2005

1. Nature of business

NuLoch Resources Inc. (the "Company") is incorporated under the laws of the Province of Alberta. The Company's activities are related to exploration for and development of petroleum and natural gas. The Company was incorporated on May 13, 2005 and commercial operations commenced on July 1, 2005. Unless otherwise indicated, comparative figures presented in respect of 2005 are as at December 31, 2005 and for the six-month period then ended.

2. Significant accounting policies

Significant accounting policies are presented in the Company's annual financial statements to be filed at www.sedar.com.



3. Property and equipment

Accumulated
depletion and Net book
Cost depreciation value
December 31, 2006
----------------------------------------------------------------------------
Petroleum and natural
gas properties $ 22,898,080 3,089,000 $ 19,809,080
Administrative assets 136,430 51,000 85,430
------------- ------------- -------------
$ 23,034,510 3,140,000 $ 19,894,510
------------- ------------- -------------
------------- ------------- -------------
December 31, 2005
----------------------------------------------------------------------------
Petroleum and natural
gas properties $ 11,362,154 1,232,000 $ 10,130,154
Administrative assets 119,952 18,000 101,952
------------ ------------- -------------
$ 11,482,106 1,250,000 $ 10,232,106
------------- ------------- -------------
------------- ------------- -------------


During the year ended December 31, 2006, general and administrative costs of $667,919 (2005 - $246,797) directly related to the acquisition, exploration and development of petroleum and natural gas reserves were capitalized.

At December 31, 2006, costs associated with unproved petroleum and natural gas properties totalling $292,000 have been excluded from the calculation of depletion and depreciation (2005 - nil).

Future development and asset retirement costs in the amount of $8,621,000 associated with proved reserves have been included in the calculation of depletion and depreciation (2005 - $10,616,000).

The carrying value of the Company's petroleum and natural gas properties was tested for impairment at December 31, 2006. The estimated undiscounted future net cash flows associated with the proved reserves plus the cost of unproved properties, net of impairments, exceeded the carrying value of property and equipment. The price applied to the proved natural gas reserves over the remaining life of the properties is based upon the benchmarks used by the Company's independent reserve evaluators, adjusted for the Company's quality and transportation differentials. The benchmarks are summarized in the following table:



Oil Oil Natural gas
WTI Edmonton AECO average
Year ($US/bbl) ($CDN/bbl) ($CDN/mcf)
---- ------------- ------------- -------------

2007 65.00 72.85 7.40
2008 69.35 77.75 8.00
2009 70.75 79.35 7.90
2010 69.00 77.30 8.00
2011 67.10 75.15 8.25
Approximate annual
escalation thereafter 2% 2% 2%


4. Acquisition

On July 1, 2005 a plan of arrangement involving Enerplus Resources Fund, TriLoch Resources Inc. and the Company became effective. Pursuant to the plan, Enerplus acquired TriLoch and virtually all of its assets in exchange for units of Enerplus. TriLoch received shares in the Company that were distributed to Class A shareholders of TriLoch and the Company received certain net assets previously held by TriLoch. The acquisition of the net assets was recorded by the Company using the continuity-of-interests method as follows:



Petroleum and natural gas properties $ 335,993
Administrative assets 108,244
Asset retirement obligations (11,000)
Future income taxes (85,000)
-------------
Class A common shares issued $ 348,237
-------------
-------------

5. Asset retirement obligations
2006 2005
------------- -------------

Balance, beginning of period $ 396,000 $ -
Liabilities acquired - 11,000
Liabilities incurred 41,000 382,000
Liabilities settled (21,000) -
Accretion expense 36,000 3,000
------------- -------------
Balance, end of period $ 452,000 $ 396,000
------------- -------------
------------- -------------


Over the next five years, asset retirement activities with an estimated future cost total of $120,000 and a present value of $103,000 are expected to be undertaken. The balance of the asset retirement obligations with an estimated future inflation adjusted cost total of $1,443,000 and a present value of $349,000 are estimated to be undertaken between 2017 and 2026.

Expected future costs assume an inflation rate of 2 percent per annum and the present value of the estimated future asset retirement obligations has been calculated using a credit-adjusted risk-free rate of 8 percent per annum.

6. Bank loan

The Company maintains a demand revolving operating credit facility with a Canadian chartered bank. The total amount of credit available under the facility is $5,500,000. Borrowings under the facility bear interest at the bank's prime rate plus 0.5 percent and are secured by a demand fixed and floating charge debenture conveying a first charge on all of the assets of the Company. The facility is subject to regular review by the bank.

7. Income taxes

The provision for income taxes differs from the amount obtained by applying the combined federal and provincial income tax rate to earnings before income taxes. The difference relates to the following items:



2006 2005
------------- -------------
Statutory tax rate 34.50% 37.62%
------------- -------------
Expected tax provision (reduction) $ (207,000) $ (494,000)
Non-deductible Crown charges 43,000 3,000
Provincial royalty credits (11,000) -
Federal resource allowance (53,000) 23,000
Stock-based compensation 18,000 10,000
Tax rate reductions (187,000) 43,000
Other 22,000 -
------------- -------------
Tax provision (reduction) $ (375,000) $ (415,000)
------------- -------------
------------- -------------

Components of the future income tax balances at December 31, 2006 and 2005
are as follows:

2006 2005
------------- -------------
Property and equipment $ (2,119,000) $ (300,000)
Asset retirement obligations 136,000 133,000
Share issue costs 373,000 196,000
Non-capital losses 413,000 526,000
------------- -------------
$ (1,197,000) $ 555,000
------------- -------------
------------- -------------


The Company carries a non-capital loss for tax purposes recorded in 2005 in the amount of $1,377,461 that can be deducted from future taxable income and expires in 2015.

8. Share capital

(a) Authorized

An unlimited number of Class A, Class B and Class C shares have been authorized.

Class B shares are exchangeable for Class A shares. The number of Class A shares obtained upon conversion of each Class B share will be equal to $10.00 divided by the greater of $1.00 and the 30-day average closing price for Class A common shares immediately prior to the effective date of conversion. Conversion may be effected by the Company in 2009 or 2010 or, if not converted before 2011, then at the option of the Class B shareholder in January 2011 or otherwise automatically on February 1, 2011.



(b) Issued and outstanding
Common
shares Amount
------------- -------------
Class A common shares
Issued upon incorporation 1 $ 1
Issued pursuant to
plan of arrangement (note 3) 2,012,694 348,237
Issued pursuant to private placement 2,800,000 700,000
Issued pursuant to
flow-through private placement 2,900,000 725,000
Share issue costs (66,846)
Tax effect of share issue costs 22,500
------------- -------------
Balance, December 31, 2005 7,712,695 1,728,892

Issued pursuant to private placement 3,050,000 5,032,500
Issued pursuant to flow-through
private placement 2,703,500 5,001,475
Issued pursuant to flow-through
private placement 1,730,800 2,250,040

Share issue costs (992,881)
Tax effect of share issue costs 313,000
Tax effect of flow-through
renunciation (244,000)
------------- -------------
Balance, December 31, 2006 15,196,995 13,089,026
------------- -------------

Class B common shares

Issued pursuant to
flow-through private placement 652,500 6,525,000
Share issue costs (601,620)
Tax effect of share issue costs 202,500
------------- -------------
Balance, December 31, 2005 652,500 6,125,880

Tax effect of flow-through
renunciation (2,196,000)
------------- -------------
Balance, December 31, 2006 652,500 3,929,880
------------- -------------

Total share capital, December 31, 2006 $ 17,018,906
-------------
-------------


In February 2006 the Company renounced tax deductions to shareholders that totalled $7,250,000 in respect of flow-through shares issued in 2005. The income tax effect of the renouncement, being $2,440,000, was recorded as a reduction in share capital and increase in future income tax liability.

(c) Stock option plan

Pursuant to its stock option plan and as authorized by the board of directors, the Company has issued stock options to directors, officers and employees. The options vest at the rate of one-third annually over three years and expire after five years. Options are issued at strike prices equal to or greater than the market price of the Company's Class A shares on the date of grant.



2006 2005
-------------------- --------------------
Weighted Weighted
average average
exercise exercise
Options price Options price
---------- -------- ---------- --------
Balance, beginning of period 822,500 $0.35 - -
Granted - - 822,500 $0.35
---------- -------- ---------- --------
Balance, end of period 822,500 $0.35 822,500 $0.35
---------- -------- ---------- --------
---------- -------- ---------- --------
Exercisable, end of period 274,165 $0.35 - -
---------- -------- ---------- --------
---------- -------- ---------- --------

At December 31, 2006 the outstanding options have a remaining life of 3.5
years (2005 - 4.5 years).

(d) Contributed surplus
2006 2005
------------- -------------

Balance, beginning of period $ 26,000 $ -
Stock-based compensation cost 52,000 26,000
------------- -------------
Balance, end of period $ 78,000 $ 26,000
------------- -------------
------------- -------------


The Company estimated the weighted average fair value of options granted in the period ended December 31, 2005 at $0.19 per option using the Black-Scholes pricing model with a risk-free interest rate of 4 percent per annum, an expected option life of five years and expected volatility of 60 percent.

(e) Per share amounts

Per share amounts have been calculated on the weighted average number of shares outstanding after giving effect to the potential conversion of Class B shares into Class A shares at 1:6.9 (2005 - 1:6.2) based on the average closing price of Class A shares of $1.45 in the 30 trading days prior to December 31, 2006 (2005 - $1.62). Options, when the exercise price is less than the average market price of the underlying security, are dilutive to net earnings per share and notionally increase the weighted average number of Class A common shares outstanding.



Period from
May 13, 2005
Year ended to
December 31, December 31,
Weighted average numbers of shares 2006 2005
----------------------------------------------------------------------------

Class A common shares 11,800,687 5,955,948
Class B common shares 652,500 501,277
Additional Class B assumed converted 3,849,750 2,606,639
------------- -------------
Basic and diluted shares outstanding 16,302,937 9,063,864
------------- -------------
------------- -------------


Stock options are anti-dilutive to net loss per share and their effect, being 571,901 shares and 401,126 shares in the periods ended December 31, 2006 and 2005, respectively, are excluded from that calculation.

9. Related parties

A director of the Company is a lawyer whose firm provides legal counsel to the Company at market rates. During 2006 amounts totalled $84,797 (2005 - $52,176).

10. Financial instruments

At December 31, 2006 and 2005 the carrying values of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities and bank loans included on the balance sheet approximate their fair values due to their short terms to maturity and the floating interest rate on the loan. The Company's accounts receivable are with customers and joint operators in the oil and natural gas industry and are subject to normal industry credit risks.

11. Commitment

In June 2006 and December 2006 the Company issued flow-through Class A common shares in the amounts of $5,001,475 and $2,250,040, respectively. In February 2007 the Company renounced these amounts of tax deductions to shareholders effective December 31, 2006 and has a commitment to incur these qualifying resource expenditures prior to December 31, 2007. As at December 31, 2006, approximately $2,400,000 of qualifying expenditures had been incurred.

12. Supplemental cash flow information

Cash payments of $48,408 have been made in respect of interest during 2006 (2005 - nil). No cash payments for taxes were made in 2006 or 2005.

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.

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.

Calculation of Finding, Development and Acquisition 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.

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.

The TSX Venture Exchange does not accept responsibility for the adequacy or accuracy of this release.

Contact Information

  • NuLoch Resources Inc.
    James N. McIndoe
    President and CEO
    (403) 920-0455
    (403) 920-0457 (FAX)
    Email: nuloch@nuloch.ca
    or
    NuLoch Resources Inc.
    2200, 444 - 5th Avenue SW
    Calgary, Alberta T2P 2T8