Midnight Oil Exploration Ltd.
TSX : MOX

Midnight Oil Exploration Ltd.

March 22, 2007 22:27 ET

Midnight Reports Fourth Quarter and Year End Financial and Operating Results

CALGARY, ALBERTA--(CCNMatthews - March 22, 2007) - Midnight Oil Exploration Ltd. (TSX:MOX) is pleased to announce its financial and operating results for the fourth quarter and year ended December 31, 2006.

HIGHLIGHTS

PRODUCTION VOLUMES

- 2006 production volumes of 2,158 boe/d

-- Increased 95% over 2005

-- Natural gas production averaged 7,755 mcf/d

-- Oil and liquids production averaged 866 boe/d

- Q4 2006 production volumes of 2,115 boe/d

-- Increased 54% over Q4 2005 and flat to Q3 2006

-- Natural gas production averaged 7,352 mcf/d

-- Oil and liquids production averaged 889 boe/d

CASH FLOW

- 2006 cash flow of $21.7 million ($0.52 per diluted share)

-- Increased 81% over 2005 (21% increase on a diluted share basis)

- Q4 2006 cash flow of $4.6 million ($0.10 per diluted share)

-- Decreased 9% over Q4 2005 and decreased 16% over Q3 2006

- Commodity prices varied over the quarter and year over year

-- 2006 Oil and NGL prices of $67.75/bbl

--- Increased 9% over 2005

-- 2006 Natural gas prices of $6.42/mcf

--- Down 29% over 2005

-- Q4 2006 Oil and NGL prices of $58.25/bbl

--- Decreased 19% over Q3 2005 and 19% over Q2 2006

-- Q4 2006 Natural gas prices of $6.84/mcf

--- Down 42% over Q4 2005 and up 17% over Q3 2006

RESERVES

- 2006 gross proved plus probable reserves of 6.49 million boe

-- Increased 31% over 2005

- 2006 gross proved reserves of 4.18 million boe

-- Increased 25% over 2005

- Additions to proved plus probable reserves replaced 2006 average production by 217%

- The net present value of total proved plus probable reserves is $118.6 million (before tax discounted at 10%)

-- Increased 40% over 2005

DRILLING ACTIVITY

- During the year we drilled 33 gross (17.2 net) wells, resulting in 18 gross (7.1 net) natural gas wells and 12 gross (8.0 net) oil wells and 3 gross (2.1 net) dry and abandoned wells for an 87.8% success rate.

- During the fourth quarter we drilled 3 gross (0.5 net) natural gas wells for a 100% success rate.


PRESIDENT'S MESSAGE

During 2006 Midnight experienced good growth and solid results with both highs and lows. We enjoyed very good drilling success on our light oil prospects at Red Earth and our sweet gas prospects in the Peace River Arch area. Overall we generated good growth but not to the level of our drilling success as rate restrictions imposed on our new oil discoveries at Red Earth restrained our production and lower than anticipated contribution from our new gas discovery at Sheldon muted some of our success.

We began the year very much on a positive note. Following our Red Earth acquisition at the end of 2005, we put in place a balanced, high potential prospect inventory bringing our large light oil opportunities at Red Earth together with a large high potential natural gas prospect inventory on the Peace River Arch. During the first quarter we pursued an aggressive program; we drilled 19 (11.1 net) wells, conducted three seismic programs, built facilities and constructed pipelines at Red Earth and Sheldon. We enjoyed good success with good results and were extremely excited about our future potential.

However during the first quarter we started to see a changing environment and quickly modified our program to meet the challenge. Climbing service costs and weakening commodity prices caused us to slow our capital program. Fortunately our proactive retrenchment proved timely and prudent. As the year rolled along several hundred barrels per day in Red Earth remained shut in due to continued government imposed rate limitations and commodity prices continued to be very volatile. In addition, at Sheldon the new gas production that had contributed up to 4.7 mmcf/d (779 boe/d) in April 2006 encountered premature water reducing sales to approximately 0.6 mmcf/d (100 boe/d) by year end. As a result under our modified capital program, we drilled only 14 (6.1 net) wells as we restricted capital to ride out the storm of higher service costs and softer commodity prices.

Perhaps our biggest challenge came on October 31, 2006, as the Federal Government dramatically altered the landscape in the oil and gas sector by reversing an earlier position and announced a number of negative tax initiatives pertaining to Energy Trusts that sent the energy stocks into a tailspin. These initiatives also impacted the valuations of junior oil and gas exploration companies and accordingly negatively impacted access to the capital markets.

Year over year, Midnight was able to grow its production, grow its reserve base and grow its prospect inventory all while ensuring our balance sheet remained healthy. We continue to develop and grow our large prospect inventory in Wapiti, Beaverlodge and Red Earth. We have a solid investment plan for 2007 and we are extremely excited about our ability to add value for the shareholders. Midnight's ability to grow in such a volatile environment is a true testament to the depth and breadth of its highly experienced and professional staff and of its multi-year high impact prospect inventory.

Hence 2006 was very much a mixed story. On the positive side, our balanced portfolio of light oil and sweet gas prospects delivered excellent drilling successes generating solid production and cash flow growth over the year. On the other side, despite our positive drilling results we were unable to realize the bounty of our success due to allowable restrictions as well as reserve and production losses. Furthermore, the overriding event for 2006 has been the capital markets pullback as our industry encountered rising service costs, lower realized commodity prices and a dramatically altered fiscal landscape due to the tax impact on the trusts and the negative spill over effect on the Juniors.

Looking into 2007 we are very optimistic about our future. We have maintained our strong technical team and we have an excellent multi-year portfolio of plays and opportunities on which to execute. Our capital budget is currently set at $30 million, and we can easily expand in a more favourable pricing environment. Based on $30 million of capital, we expect our production to average 2,750 boe/d in 2007.

Mr. Paul Moynihan, Chairman of the Board has advised us of his intention not to stand for re-election at the next Annual meeting. Mr. Moynihan has been a long time member of the Midnight team dating back to our predecessor Midnight Oil & Gas. We would like to express our sincere thanks and appreciation to Paul for his assistance and his valuable contribution.

At Midnight, we definitely see these times as opportunities and are very well situated to take advantage of these opportunities.

Shareholders are invited to attend Midnight's 2006 Annual and Special Meeting of Shareholders scheduled for 10:00 AM, Friday May 11, 2007 at the Sun Life Conference Centre, located at 140 4th Avenue S.W., Calgary, Alberta.

Signed "Fred Woods"

Fred Woods

President and Chief Executive Officer

March 21, 2007

RESERVES

The reserve data set forth below is based on an independent reserves evaluation conducted by GLJ Petroleum Consultants Ltd. ("GLJ") effective December 31, 2006 ("GLJ Report") and prepared in accordance with the definitions set out under National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). Midnight has a reserves committee comprised of independent board members which reviews the qualifications and appointment of the independent reserve evaluators. The committee also reviews the process for providing information to the evaluators and meets with the independent evaluators to discuss the procedures used in the independent report, to review the Company's major properties and to identify and discuss any areas of risk. The GLJ Report was reviewed by the reserves committee of Midnight and was approved by the Company's Board of Directors on March 21, 2007.

The reserve highlights are:

- Gross proved plus probable reserves at December 31, 2006 were 6.49 million boe, a 31% increase from 4.97 million boe of proved plus probable reserves at December 31, 2005.

- Gross proved reserves at December 31, 2006 were 4.18 million boe, a 25% increase from 3.35 million boe of proved reserves at December 31, 2005.

- Additions to proved plus probable reserves replaced 2006 average production by 217%.

- The net present value (before tax discounted at 10%) of total proved plus probable reserves increased 40% to $118.6 million.



FORECAST PRICES AND COSTS

Summary of Oil and Gas Reserves - Gross and Net Reserves

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Reserves Light and Natural Gas
Category Medium Oil Natural Gas Liquids Total
-----------------------------------------------------------
Gross Net Gross Net Gross Net Gross Net
(Mbbls) (Mbbls) (MMcf) (MMcf) (Mbbls) (Mbbls) (Mboe) (Mboe)
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Proved
Developed
Producing 1,210 1,080 11,968 9,340 278 183 3,483 2,820
Developed
Non-Producing 13 12 2,198 1,652 45 30 424 317
Undeveloped 219 192 272 211 8 5 272 233
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Total Proved 1,443 1,285 14,438 11,204 330 218 4,180 3,370
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Probable 1,183 1,044 6,084 4,774 109 71 2,306 1,911
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Total Proved
Plus Probable 2,626 2,328 20,522 15,978 439 289 6,486 5,280
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Notes:

(1) Gross reserves means our working interest (operating and non-operating)
share before deduction of royalties and without including any royalty
interest received by us.

(2) Net reserves means our working interest (operating and non-operating)
after deduction of royalties obligations, plus our royalty interests in
production or reserves.

(3) Natural gas is converted to barrels of oil equivalent ("boe") at a ratio
of six thousand cubic feet to one boe.

(4) Boe's may be misleading, particularly if used in isolation. In
accordance with NI 51-101, a boe conversion ratio for natural gas of
6 Mcf:1 bbl has been used which is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.

(5) May not add due to rounding.


NET PRESENT VALUE ("NPV") SUMMARY 2006

Midnight's crude oil, natural gas and natural gas liquids reserves were evaluated using GLJ's product price forecasts effective January 1, 2007 prior to provision for income taxes, interest, debt service charges and general and administrative expenses. It should not be assumed that the discounted future net production revenues estimated by GLJ represent the fair market value of the reserves.



Net Present Value of Reserves, before income taxes
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December 31, 2006
(000's) 0% 5% 10% 15% 20%
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Proved Reserves
Developed Producing 109,484 91,298 79,125 70,348 63,684
Developed Non-Producing 11,698 8,787 6,962 5,740 4,879
Undeveloped 6,742 4,702 3,350 2,403 1,712
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Total Proved 127,925 104,788 89,437 78,491 70,275
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Probable 74,241 43,618 29,127 20,895 15,663
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Proved plus Probable 202,166 148,406 118,564 99,386 85,938
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At December 31, 2006 using a 10% discount factor, the proved producing reserves make up 67% of the proved plus probable value while total proved reserves account for 75% of the proved plus probable value. Midnight's proved non-producing and undeveloped reserves account for only 0.7 million of the total proved reserves booked. The future capital associated with these proved reserves included in the 2006 GLJ Report is approximately $6.2 million.

The GLJ's price forecast utilized in the forecast evaluation is summarized
below.



GLJ January 1, 2007 Price Forecast
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West Texas Edmonton
Intermediate Light Natural Gas Foreign
Year Crude Oil Crude Oil at AECO Exchange
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($US/bbl) ($Cdn/bbl) ($Cdn/mmbtu) ($US/$Cdn)

2007 62.00 70.25 7.20 0.87
2008 60.00 68.00 7.45 0.87
2009 58.00 65.75 7.75 0.87
2010 57.00 64.50 7.80 0.87
2011 57.00 64.50 7.85 0.87
2012 57.50 65.00 8.15 0.87
2013 58.50 66.25 8.30 0.87
2014 59.75 67.75 8.50 0.87
2015 61.00 69.00 8.70 0.87
2016 62.25 70.50 8.90 0.87
2017 63.50 71.75 9.10 0.87
Escalate thereafter at +2.0%/yr +2.0%/yr +2.0%/yr -
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RESERVE RECONCILIATION

Reconciliation of Changes in Company Gross Reserves by Principal Product
Type Forecast Prices and Costs

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Crude Oil & NGLs Natural Gas Total
------------------------------------------------------------
Proved Proved Proved
Plus Plus Plus
Proved Probable Proved Probable Proved Probable
Factors (Mbbls) (Mbbls) (MMcf) (MMcf) (Mboe) (Mboe)
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December 31,
2005 1,344 2,375 12,040 15,549 3,351 4,966
Extensions 245 534 3,892 5,758 893 1,494
Improved
Recovery - - 151 190 26 32
Technical
Revisions 21 (265) (99) 252 5 (223)
Discoveries 479 738 1,285 1,604 693 1,005
Acquisitions - - - - - -
Dispositions - - - - - -
Economic
Factors - - - - - -
Production (316) (316) (2,831) (2,831) (788) (788)
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December 31,
2006 1,773 3,066 14,438 20,522 4,180 6,486
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Notes:

(1) Gross reserves means our working interest (operating and non-operating)
share before deduction of royalties and without including any royalty
interest received by us.

(2) Natural gas is converted to barrels of oil equivalent ("boe") at a ratio
of six thousand cubic feet to one boe.

(3) May not add due to rounding.


FINDING, DEVELOPMENT AND ACQUISITION ("FD&A") COSTS

Midnight's capital expenditures on exploration and development totalled $61.7 million in 2006 with no acquisitions in the current year. On a proven plus probable reserve basis, the Company's finding, development and acquisition cost for 2006 was $27.14 per boe. The calculation of finding, development and acquisition cost for proved plus probable reserves includes future capital of $19.3 million included in the 2006 GLJ Report, and deducts $18.4 million of future capital which was included in the 2005 GLJ Report. On a proven reserve basis, the Company's finding, development and acquisition cost for 2006 was $35.90 per barrel of oil equivalent, down 8.5% from 2005. The calculation of finding, development and acquisition cost for proved reserves includes future capital of $6.2 million included in the 2006 GLJ Report, and deducts $9.9 million of future capital which was included in the 2005 GLJ Report.

Future Development Capital ("FDC")

NI 51-101 requires that FD&A costs be calculated including changes in FDC. Changes in forecast FDC occur annually as a result of development activities, acquisition and disposition activities and capital cost estimates that reflect the independent evaluator's best estimate of what it will cost to bring the proved undeveloped and probable reserves on production. The current high level of activity has resulted in increased capital costs throughout the industry that are now reflected in the estimates of future development costs effective December 31, 2006.



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FD&A Costs - Company
Interest Reserves
2006 2005
----------------------------------------------------------------------------
Proved plus Proved plus
Proved Probable Proved Probable
----------------------------------------------------------------------------
Capital costs ($000's)

Exploration and
Development 61,733 61,733 28,832 28,832
Acquisitions n/a n/a 47,666 47,666
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61,733 61,733 76,498 76,498
Change in Exploration and
Development FDC (3,715) 906 2,502 5,759
Acquisition FDC n/a n/a 3,923 8,350
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58,018 62,639 82,923 90,607
Reserve
additions(1)(Mboe)

Exploration and
Development 1,617 2,308 1,130 1,326
Acquisitions n/a n/a 984 1,914
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1,617 2,308 2,114 3,240
Finding, development and
acquisition costs ($/boe)
Exploration and
Development Capital
including change in FDC $ 35.88 $ 27.14 $ 27.72 $ 26.09
Acquisition Capital
including FDC n/a n/a $ 52.42 $ 29.27
Total Capital including
change in FDC $ 35.88 $ 27.14 $ 39.22 $ 27.97

Exploration and
Development Capital
excluding change in FDC $ 38.18 $ 26.75 $ 25.51 $ 21.75
Acquisition Capital
excluding FDC n/a n/a $ 48.43 $ 24.91
Total Capital excluding
change in FDC $ 38.18 $ 26.75 $ 36.18 $ 23.61
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Notes:

(1) Reserve additions are presented net of technical revisions.

(2) The aggregate of the exploration and development costs incurred in the
year and the change during the year in estimated future development
costs generally will not reflect total finding and development costs
related to reserves.


Net Asset Value

At December 31, 2006, Midnight had a net asset value of $2.67 per basic share discounting the present value of proved and probable reserves at 10% before tax. The present value of petroleum and natural gas reserves were determined by GLJ in their year end evaluation. Undeveloped land at December 31, 2006 was internally valued at an average price of $150 per acre, and undeveloped seismic and other assets were internally evaluated based on cost.



Net Asset Value- Forecast Pricing and
Costs at December 31, 2006
Mboe $/Boe PV ($M) $/Share
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Proved Reserves Value at 10% BIT 4,180 21.40 89,437 $ 1.87
Probable Reserves Value at 10% BIT 2,306 12.63 29,127 0.61
---------------------------------
Proved plus Probable Reserves Value at
10% BIT 6,486 18.28 118,564 $ 2.48

(000's) $/acre
Undeveloped Land 173 acres 150 25,965 0.54
Seismic and Other Assets 5,243 0.11
Net Debt (21,974) (0.46)
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Total Net Assets 127,798 2.67
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Basic Shares Outstanding 47,828
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NET ASSET VALUE $ 2.67
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At December 31, 2006 there are no material differences between basic and fully diluted net asset value calculations.


MANAGEMENT'S DISCUSSION AND ANALYSIS

The following Management Discussion and Analysis as provided by the management of Midnight should be read in conjunction with the audited Consolidated Financial Statements and accompanying notes for the years ended December 31, 2006 and 2005. Additional information relating to Midnight, including a detailed reserve analysis, will be included in our Annual Information Form, which may be found on SEDAR at www.sedar.com.

Basis of Presentation - The financial data presented below has been prepared in accordance with Canadian Generally Accepted Accounting Principles ("GAAP"). The reporting and the measurement currency is the Canadian dollar. For the purpose of calculating unit costs, natural gas is converted to a barrel equivalent ("boe") using six thousand cubic feet of natural gas equal to one barrel of oil unless otherwise stated. The following Management Discussion and Analysis compares the results of the year ended December 31, 2006 ("2006") to the year ended December 31, 2005 ("2005") and the results of the three months ended December 31, 2006 ("Q4 2006") to the three months ended December 31, 2005 ("Q4 2005") and the three months ended September 30, 2006 ("Q3 2006").

Non-GAAP Measurements - Within the Management Discussion and Analysis references are made to terms commonly used in the oil and gas industry. Funds from operations, funds from operations per share and netbacks are not defined by GAAP in Canada and are referred to as non-GAAP measures. Funds from operations per share is calculated based on the weighted average number of common shares outstanding consistent with the calculation of net income per share. Netbacks equal total revenue less royalties, operating costs and transportation costs calculated on a boe basis. Management utilizes these measures to analyze operating performance and leverage. Funds from operations is commonly referred to as cash flow by research analysts and is used to value and compare oil and gas companies and is frequently included in published research when providing investment recommendations. Funds from operations is calculated as cash provided by operations (as detailed on the Statement of Cash Flows) before changes in non-cash working capital. Total boes are calculated by multiplying the daily production by the number of days in the period.

Forward Looking Statements - Certain statements contained within the Management Discussion and Analysis, and in certain documents incorporated by reference into this document, constitute forward-looking statements. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek", "anticipate", "budget", "plan", "continue", "estimate", "expect", "forecast", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions. 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. We believe the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in, or incorporated by reference into, this Management Discussion and Analysis should not be unduly relied upon. These statements speak only as of the date of this Management Discussion and Analysis or as of the date specified in the documents incorporated by reference into this Management Discussion and Analysis, as the case may be.

In particular, this Management Discussion and Analysis, and the documents incorporated by reference, contain forward-looking statements pertaining to the following:

- the performance characteristics of our oil and natural gas properties;

- oil and natural gas production levels;

- the size of the oil and natural gas reserves;

- projections of market prices and costs;

- supply and demand for oil and natural gas;

- expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development;

- treatment under governmental regulatory regimes and tax laws; and

- capital expenditures programs.

The actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this Management Discussion and Analysis:

- volatility in market prices for oil and natural gas;

- liabilities inherent in oil and natural gas operations;

- uncertainties associated with estimating oil and natural gas reserves;

- competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel;

- incorrect assessments of the value of acquisitions;

- geological, technical, drilling and processing problems; and

- changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry;

Statements relating to "reserves" or "resources" are deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future. Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward looking statements contained in this Management Discussion and Analysis and the documents incorporated by reference herein are expressly qualified by this cautionary statement. We do not undertake any obligation to publicly update or revise any forward-looking statements except as required by securities law.

This Management Discussion and Analysis is dated as of March 21, 2007.



Selected Annual & Quarterly Information

Set out below is selected annual information for Midnight for the last two
years and for the period from inception on November 29, 2004 to December 31,
2004:

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Financial
(000's, except for per
share amounts) 2006 2005 2004
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Petroleum and natural gas sales $ 39,688 $ 22,989 $ 977
Funds from operations 21,702 11,967 397
Per share - Basic 0.52 0.44 0.02
- Diluted 0.52 0.43 0.02
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Net income $ 45 $ 1,669 $ 15

Per share - Basic 0.00 0.06 0.00
- Diluted 0.00 0.06 0.00
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Additions to capital assets $ 61,752 $ 76,507 $ 2,680

Net debt 21,974 16,730 (2,902)
Total assets 152,833 111,171 42,120
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Shares outstanding
Basic 47,828 38,328 26,328
Diluted 53,548 41,511 28,661
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Operations

Average daily production
Natural gas (mcf/d) 7,755 4,666 3,549
NGLs & oil (bbls/d) 866 326 132
Combined (boe/d) 2,158 1,104 723
Netback (boe) $ 31.79 $ 33.07 $ 23.04
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Set out below is selected information by quarter for Midnight for the last
eight quarters:

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Financial 2006 2005
------------------------------- ------------------------------
(000's, except
for per share
amounts) Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
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Petroleum
and natural
gas sales $ 9,410 $10,099 $10,988 $ 9,191 $ 8,772 $5,997 $ 5,050 $3,170
Funds from
operations 4,555 5,445 6,515 5,187 4,991 3,073 2,374 1,529
Per share
- Basic 0.10 0.13 0.16 0.14 0.16 0.12 0.09 0.06
- Diluted 0.10 0.13 0.16 0.13 0.16 0.12 0.09 0.06
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Net income
(loss) $ (565)$ 320 $ 82 $ 208 $ 864 $ 487 $ 158 $ 160
Per share
- Basic (0.01) 0.01 0.00 0.01 0.03 0.02 0.01 0.01
- Diluted (0.01) 0.01 0.00 0.01 0.03 0.02 0.01 0.01
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Additions to
capital
assets $ 8,652 $13,670 $ 9,945 $29,485 $55,285 $8,175 $ 4,482 $8,565
Net debt 21,974 33,579 25,297 41,028 16,730 11,344 6,242 4,134
Total assets 152,833 147,677 138,842 134,452 111,171 54,187 47,350 45,106
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Shares
outstanding
Basic 47,828 42,328 42,328 38,328 38,328 26,328 26,328 26,328
Diluted 53,548 45,914 45,903 41,495 41,511 29,360 29,393 28,821
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Operations
Average
daily
production
Natural gas
(mcf/d) 7,352 7,637 10,091 5,926 4,694 4,885 5,151 3,924
NGLs & oil
(bbls/d) 890 841 830 901 600 270 297 135
Combined
(boe/d) 2,115 2,114 2,512 1,889 1,382 1,084 1,156 788
Netback
(boe) $ 29.08 $ 33.15 $ 31.68 $ 33.54 $ 43.68 $34.21 $ 25.48 $23.72
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Midnight has grown substantially over the past two years. Production has increased from 788 boe/d in Q1 2005 to 2,115 boe/d in Q4 of 2006. Funds from operations is a key operating measure in our business and is primarily derived from our petroleum and natural gas sales, which is from production being sold at prevailing commodity prices. 2006 saw considerable volatility in the prices for both crude oil and natural gas while 2005 experienced a quarter over quarter upward trend in commodity prices for both products. World crude prices continued to be positively influenced by a tight supply for the first half of 2006 but warmer than predicted weather for the fall and winter of 2006 combined with a strengthening in supply caused the price of oil to drop significantly by November 2006. Oil prices closed the year effectively flat with year-end 2005 prices. A cold start to the winter in December 2005 led to record natural gas prices at the end of 2005. However, this was followed by one of the warmest Januarys on record putting gas storage at above average levels entering into the injection season. This resulted in a 33% decline in Alberta spot prices for the month of January 2006. In addition, storage levels continued to increase over the summer months with lower than average cooling demands and gas deliveries continuing unimpeded through production and distribution infrastructures that had been previously damaged by the 2005 hurricanes. This increase in natural gas supply resulted in continued downward pressure on gas prices through to the end of the year. Midnight's production grew quarter over quarter from Q1 2005 of 788 boe/d until Q2 2006 where we reached 2,512 boe/d with flush natural gas production. During Q4 2005 we acquired the Red Earth property significantly adding to our oil portfolio. Oil production remained relatively flat for 2006 as Red Earth production remained subject to Maximum Rate Limitations for the year. Throughout 2005 and 2006 the cost of services escalated dramatically with the increase in demand for these services resulting in reduced margins for most oil and gas exploration and production companies. On October 31, 2006, the Federal Government dramatically altered the investment landscape in the oil and gas sector by announcing a number of negative tax initiatives pertaining to income trusts in the resource sector. These initiatives also impacted the valuations of junior oil and gas exploration companies and accordingly negatively impacted their access to capital markets.

Relationship with Daylight Energy Ltd. ("Daylight")

Midnight and Daylight operated under an Administrative and Technical Services Agreement (TSA) which provided for the sharing of services required to manage Midnight's activities and govern the allocation of general and administration expenses between the entities. Under this agreement, Daylight had been the employer on behalf of the parties and received payment for certain technical and administrative services provided to Midnight. In September 2006, Midnight and Daylight agreed that the TSA would be changed in scope to enable Midnight to operate without the technical and other services provided by Daylight. The fourth quarter of 2006 was a transition period in this regard, and effective October 1, 2006 the Administrative and Technical Services Agreement was amended to only charge Midnight for certain shared services including: land administration, drilling and completion operations, marketing, certain accounting and human resources and administration functions. During the fourth quarter, Midnight incurred direct charges for technical personnel including: geologists; geophysicists; engineers; land negotiators; business development; land administrators and finance personnel who were functioning independently from Daylight. Effective December 31, 2006 the Administrative and Technical Services Agreement was terminated. Certain administrative services will continue beyond 2006 through an agreed upon monthly fee for service basis, which may be cancelled by either party.

Production

Midnight's production averaged 2,158 boe/d for 2006 a 95% increase over 2005 production. During 2006, production was comprised of 7,755 mcf/d of natural gas, 706 bbl/d of oil and 160 bbl/d of natural gas liquids ("NGLs"). Natural gas production increased to 7,755 mcf/d from 4,666 mcf/d in 2005 due to our successful drilling program focused in the Peace River Arch where we added production in Wapiti and Beaverlodge. At Sheldon production came on at high rates during Q2 of 2006, but declined rapidly by Q3. Despite this, our production adds in Wapiti and Beaverlodge resulted in a 56% increase in gas production for the second half of 2006 compared to the second half of 2005. Oil production increased significantly over 2005 having benefited from a full year of reported results from our light oil property in Red Earth, which we acquired on November 30, 2005. Red Earth oil production comprised 85% of total oil production in 2006. Oil production from Red Earth has remained relatively flat for much of the year as production has been subject to Maximum Rate Limitations ("MRLs"). Applications for Good Production Practice ("GPP") were submitted but not yet approved prior to year end. This resulted in a lower exit production rate than what Midnight previously projected. NGLs production for 2006 did not change from 2005 as our gas production additions during the year did not have significant associated liquids production.

Midnight's Q4 2006 production averaged 2,115 boe/d which was consistent with Q3 2006 production and was an increase of 53% from Q4 2005. Q4 production of 2,115 boe per day consisted of 7,352 mcf per day of natural gas, 694 bbls per day of oil and 195 bbls per day of natural gas liquids. Q4 2006 production increased from Q4 2005 due to our acquisition of, and the successful drilling on, the Red Earth properties and the grass roots natural gas exploration programs in the Peace River Arch area and in West Central Alberta.

Midnight has budgeted 2007 production to average 2,750 boe/d with Q1 2007 forecast to average 2,300 boe/d.



The following table outlines our production volumes for the periods
indicated below:

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Production Q4 Q4 Q3
2006 2005 2006 2006 2005
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Natural Gas (mcf/d) 7,352 4,694 7,637 7,755 4,666
Oil (bbls/d) 694 470 704 706 166
NGLs (bbls/d) 195 130 137 160 160
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Total (boe/d) 2,115 1,382 2,114 2,158 1,104
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Pricing

Midnight's natural gas prices are influenced by overall North American supply and demand balance, seasonal changes, storage levels and transportation capacity. Midnight markets its natural gas on a daily spot market basis at various delivery points in Alberta and therefore, the average Alberta spot market price in Canadian dollars per mcf is an appropriate benchmark for our gas prices. We continue to receive a slight premium to the Alberta spot price for our gas sales and expect our future realized price to coincide with the Alberta spot price.

Midnight's realized oil price has a high correlation to the Edmonton Par benchmark price which generally has a strong correlation to the US benchmark West Texas Intermediate at Cushing, Oklahoma ("WTI") price adjusted by the Canadian to US dollar exchange rate. Canadian light oil prices correlate to refinery postings that adjust WTI for the Canadian to US dollar exchange rate as well as transportation costs and quality adjustments. Midnight's oil price is significantly influenced by global supply and demand. During 2006, although the oil price saw wide fluctuations compared to historical averages, the WTI price has been strong which increased the price realized by Midnight.

Prices for Natural Gas Liquids have their own market dynamic. NGLs include condensate, pentane, butane and propane. While prices for condensate and pentane have a relatively strong correlation to oil prices, prices for butane and propane trade at varying discounts due to the market conditions of local supply and demand. Year-over-year and quarter-over-quarter, Midnight's realized price for commodities has tracked with the appropriate benchmark prices.

Midnight did not buy or sell any commodity or currency hedges during the period.



The following table outlines benchmark prices compared to Midnight's
realized prices:

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Prices and Marketing Q4 Q4 Q3
2006 2005 2006 2006 2005
----------------------------------------------------------------------------
Benchmark Prices
----------------------------------------------------------------------------
Alberta spot ($/mcf) $ 6.77 $ 11.46 $ 5.58 $ 6.38 $ 8.65
WTI oil ($US/bbl) 59.96 60.02 70.48 66.09 56.59
Cdn/US average exchange rate 0.878 0.852 0.892 0.882 0.826
Edmonton Par ($/bbl) $ 64.94 $ 71.40 $ 79.69 $ 73.25 $ 69.18
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Midnight's Realized Price
----------------------------------------------------------------------------
Natural gas ($/mcf) $ 6.84 $ 11.73 $ 5.85 $ 6.42 $ 9.07
Oil ($/bbl) 62.23 68.02 79.17 70.20 68.68
NGLs ($/bbl) 44.14 59.52 65.94 56.92 55.79
Combined oil & NGLs ($/bbl) 58.25 66.19 77.01 67.75 62.35
Total ($/boe) $ 48.35 $ 69.02 $ 51.92 $ 50.38 $ 57.04
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Petroleum and Natural Gas Sales

Petroleum and natural gas sales totalled $39.7 million for 2006, up 73% from $23.0 million in 2005. Q4 2006 sales were $9.4 million versus $8.8 million in Q4 2005 and $10.1 million in Q3 2006. The sales increase in 2006 over 2005 was entirely due to increased production as realized selling price decreased from 2005. The increase in production volumes accounted for increased sales of $21.9 million which was offset by reduced commodity prices which reduced revenue by $5.2 million compared to 2005. Q4 2006 sales were up $0.6 million from Q4 2005 with production gains accounting for $4.6 million of the sales increase, while decreased commodity prices reduced revenue by $4.0 million.



The following table outlines our production sales for the periods indicated
below:

----------------------------------------------------------------------------
Petroleum and Natural Gas Sales Q4 Q4 Q3
(000's) 2006 2005 2006 2006 2005
----------------------------------------------------------------------------
Natural Gas $ 4,628 $ 5,065 $ 4,112 $ 18,169 $ 15,443
Oil 3,975 2,939 5,128 18,079 4,164
NGLs 795 709 833 3,324 3,263
Royalty income 12 59 26 116 119
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Total $ 9,410 $ 8,772 $ 10,099 $ 39,688 $ 22,989
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Royalties

Royalty payments are made to the owners of the mineral rights on our leases which include provincial governments (Crown) and freehold landowners as well as to other third parties by way of contractual overriding royalties.

In Alberta, royalties on natural gas and NGLs are charged by the government based on an established monthly Reference Price. The Reference Price is meant to reflect the average price for gas and NGLs in Alberta. Gas cost allowance, custom processing credits, and other incentive programs reduce the effective royalty rate.

Oil royalty rates are generally a function of production rates on a per well basis and market prices. They may also be subject to certain reductions and incentives. Crown royalties in Alberta are generally satisfied by delivering the required amount of oil to the Crown.

YTD 2006 royalties have decreased to 17.8% of revenue from 25.9% of revenue for the corresponding period in 2005. Both natural gas and oil royalty rates have decreased from 2005. Natural gas royalty rates have decreased with increased gas cost allowance in the year from our ownership interest in the Red Earth Gas plant and have also been reduced by prior year gas cost allowance adjustments related to our ownership interest in our West Central facilities. Natural gas royalty rates before Gas Cost Allowance averaged 26.4% for the year. Oil royalty rates for 2006 are lower than the 2005 rates as during the year certain wells in the Red Earth area received a Third Tier Exploratory Royalty Exemption resulting in no crown royalties on these wells for a period of time. Under this program exploratory oil wells are exempt from royalties for up to one year or $1 million in royalties. Royalty rates as a percentage of revenue have also decreased with an increased ratio of oil in our production portfolio which is subject to lower royalty rates bringing down our overall percentage. Q4 2006 royalties averaged 15.5% of revenue for the period versus 19.5% for Q3 2006 and 24.8% for Q4 2005. Gas royalty rates accounted for the largest decrease due to increase gas cost allowance booked in Q4 2006. Effective January 1, 2007 ARTC has been eliminated. The impact of the Third Tier Exploratory Royalty Exemption will be minimized in 2007, causing oil royalty rates to rise back to the 20% level resulting in the overall effective royalty rate increasing in 2007.



The following tables outline our royalties by type and by commodity:

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Royalties by Type (000's) Q4 Q4 Q3
2006 2005 2006 2006 2005
----------------------------------------------------------------------------
Crown $ 1,461 $ 2,083 $ 2,006 $ 6,840 $ 5,484
Gross overriding 126 232 87 711 897
ARTC (125) (143) (127) (500) (428)
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Total $ 1,462 $ 2,172 $ 1,966 $ 7,051 $ 5,953
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$/boe $ 7.51 $ 17.09 $ 10.11 $ 8.95 $ 14.77
----------------------------------------------------------------------------
----------------------------------------------------------------------------
% of revenue 15.5 24.8 19.5 17.8 25.9
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----------------------------------------------------------------------------
Royalties by Commodity Q4 Q4 Q3
(excluding ARTC) 2006 2005 2006 2006 2005
----------------------------------------------------------------------------
Natural Gas
000's $ 695 $ 1,319 $ 837 $ 3,711 $ 4,408
% of revenue 15.0 26.0 20.4 20.4 28.5
----------------------------------------------------------------------------
Oil
000's $ 627 $ 811 $ 1,048 $ 2,891 $ 1,007
% of revenue 15.8 27.6 20.4 16.0 24.2
----------------------------------------------------------------------------
NGLs
000's $ 265 $ 185 $ 208 $ 949 $ 966
% of revenue 33.3 26.1 25.0 28.5 29.6
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Operating Expenses

Operating expenses during 2006 were $9.28/boe which is consistent with 2005 operating expenses of $9.17/boe and with our forecast level. Q4 2006 operating costs of $11.51/boe were up over prior quarters. Operating costs were negatively impacted by high water disposal fees at Sheldon for current and prior periods and by unanticipated third party charges for the year relating to our Red Earth area of operation. The facility and tie in work performed at Red Earth in 2006 is expected to have a positive impact on operating costs in 2007. We anticipate operating costs to remain in the $8.50 to $9.50 per boe range for 2007.



----------------------------------------------------------------------------
Operating Expenses (000's) Q4 Q4 Q3
2006 2005 2006 2006 2005
----------------------------------------------------------------------------
Operating expenses $ 2,239 $ 1,044 $ 1,657 $ 7,305 $ 3,697
----------------------------------------------------------------------------
Total ($/boe) $ 11.51 $ 8.22 $ 8.52 $ 9.28 $ 9.17
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----------------------------------------------------------------------------


Transportation Expenses

Transportation expenses are defined by the point of legal custody transfer of the commodity and are influenced by the nature of the production, location, availability of transportation and the sales point. The cost of delivering production to the custody transfer point is shown separately as transportation expense.

Transportation charges have increased from 2005 as recent discoveries at Red Earth are outside the pipeline grid and require oil to be trucked to the sales point. Natural gas is usually transported through owned or third party infrastructure to an established delivery point such as AECO in Alberta at an agreed tariff and then delivered to the purchaser. As we tie in oil wells at Red Earth the 2007 transportation charge is expected to decline.



----------------------------------------------------------------------------
Transportation Expenses (000's) Q4 Q4 Q3
2006 2005 2006 2006 2005
----------------------------------------------------------------------------
Transportation expenses $ 49 $ 3 $ 28 $ 282 $ 11
$ per boe $ 0.25 $ 0.03 $ 0.14 $ 0.36 $ 0.03
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Interest Expense

The 2006 interest expense totalled $1,019,000 representing an effective interest rate of 5.4% on average bank debt of $18.8 million. During 2005 we had less bank debt and incurred $187,000 of interest expense on average bank debt of $4.0 million for an effective interest rate of 4.2%. The effective interest rate on our bank debt has fluctuated with the changes in the Bank of Canada rates. Our effective interest rate in 2007 is expected to fluctuate with the changes in the Bank of Canada rates and our net debt to cash flow ratio.

General and Administration Expenses

During Q4 2006 and the year ended 2006, cash general and administration ("G&A") expenses totalled $580,000 ($2.98/boe) and $2,160,000 ($2.74/boe) respectively compared to $491,000 ($3.86/boe) and $1,202,000 ($2.98) for the same periods in 2005. Midnight's general and administration expenses have been allocated based on the Administrative and Technical Service Agreement ("TSA") with Daylight. Under this agreement, Daylight had been the employer on behalf of the parties and received payment for certain technical and administrative services provided to Midnight. The Company has been charged for its direct activities and for its proportionate share of overhead based on production and capital spending. Capitalized G&A is derived directly from the capital portion of the Administrative and Technical Service Agreement combined with an allocation of exploration staff burden for the fourth quarter of 2006.

In September 2006, initiated by the merger of Daylight and Sequoia Oil & Gas Trust, Midnight and Daylight agreed that the TSA would change in scope to enable Midnight to operate without the technical and other services provided by Daylight. The fourth quarter of 2006 was a transition period in this regard, and effective October 1, 2006 the TSA was modified to only charge Midnight for certain shared services including: land administration; drilling and completion operations; marketing; and certain accounting and human resources and administration functions. During the fourth quarter, Midnight incurred direct charges for technical personnel including: geologists; geophysicists; engineers; land negotiators; business development; land administrators and finance personnel who were functioning independently from Daylight as a result, direct G&A increased substantially over previous quarters.

Included in direct charges for Q3 2006 Midnight matched employee contributions and contributed $55,000 to Habitat for Humanity to assist in building affordable housing in our community; we did not have a similar charge in Q4 2006 but continue to contribute by providing manpower on certain designated work days. The increases in direct G&A for Q4 2006 were partially offset by a reduction in the Technical Service fee from Daylight.

Effective December 31, 2006 the Administrative and Technical Services Agreement was terminated. Certain administrative services will continue beyond 2006 through an agreed upon fee for service basis, which may be cancelled by either party.

Midnight expects cash G&A to increase to $3 to $4 per boe in 2007 with increased labour costs and additional charges to operate on a stand alone basis.

Stock-Based Compensation

The Company applies the fair value method for valuing stock option grants and warrants. Under this method, compensation costs attributable to all share options granted and warrants issued are measured at fair value at the grant and issuance date and expensed over the vesting period with a corresponding increase to contributed surplus. The stock-based compensation associated with the salaries capitalized in cash general and administration expenses are also capitalized. Midnight recognized stock-based compensation expense of $765,000 for 2006 and capitalized a corresponding $417,000. Additional stock options were granted during Q4 2006 with a weighted average fair value of $0.85 per option. Midnight's unamortized portion of stock-based compensation is $3.0 million at December 31, 2006.



The components of general and administration expense are as follows:

----------------------------------------------------------------------------
General and Administration
Expenses Q4 Q4 Q3
(000's) 2006 2005 2006 2006 2005
----------------------------------------------------------------------------
Direct G&A $ 896 $ 195 $ 207 $ 1,377 $ 448
Technical service fee from
Daylight 713 948 950 3,749 2,622
Overhead recoveries from
Daylight (238) (77) (103) (649) (241)
Capitalized G&A (791) (575) (409) (2,317) (1,627)
----------------------------------------------------------------------------
Cash G&A $ 580 $ 491 $ 645 $ 2,160 $ 1,202
Stock-based compensation 101 152 94 348 449
----------------------------------------------------------------------------
Net G&A $ 681 $ 643 $ 739 $ 2,508 $ 1,651
----------------------------------------------------------------------------

Cash G&A ($/boe) $ 2.98 $ 3.86 $ 3.32 $ 2.74 $ 2.98
Stock-based compensation ($/boe) 0.52 1.19 0.48 0.44 1.11
----------------------------------------------------------------------------
Net G&A ($/boe) $ 3.50 $ 5.05 $ 3.80 $ 3.18 $ 4.09
----------------------------------------------------------------------------
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Depletion, Depreciation and Accretion

For 2006, depletion, depreciation and accretion ("DD&A") was $21.7 million versus $8.5 million for 2005. The increase is a result of higher production and a larger capital base being depleted as well as depleting at a higher rate from higher finding and development costs. On a boe basis, the 2006 charge for DD&A increased to $27.51 from $20.98 in 2005. The increase is a result of higher finding costs, primarily related to our acquisition of the Red Earth property in Q4 of 2005 and the $12.4 million of capital invested in the Sheldon area in 2006 with nominal reserves assigned.

For Q4 2006, DD&A was $5.7 million versus $4.8 million for Q3 2006 and $3.4 million for Q4 2005. On a boe basis, Q4 2006 DD&A was $29.34 versus Q3 2006 DD&A charge of $24.88. Midnight expects to continue to lower its depletion and depreciation rate as we add additional proved reserves at a lower cost than our current rate.

Taxes

For 2006, the future tax recovery was $60,000. The future tax recovery for Q4 2006 was $457,000. The difference in the expected rate of 34.5% and the effective rate is from permanent differences relating to stock-based compensation and the difference between non-deductible Crown charges and the resource allowance as well as the effects of finalizing 2005 tax pool balances and adjusting for the changes in the statutory tax rate.

During Q2 2006, Midnight issued $20.4 million of flow-through shares, the effect of this issue on future taxes will be recognized when the expenditures are renounced in Q1 2007.

Midnight does not expect to become taxable on an income tax basis in 2007 and has approximately $145 million in tax pools to shelter taxable income in future years prior to the renunciation of the flow-through expenditures detailed as follows:



----------------------------------------------------------------------------

Tax Pools (000's) 2006
----------------------------------------------------------------------------
Canadian exploration expense $ 32,200
Canadian development expense 19,100
Canadian oil and gas property expense 59,700
Undepreciated capital cost 30,600
Share issue costs 3,800
----------------------------------------------------------------------------
Total $ 145,400
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Funds from Operations and Net Income

For 2006, funds from operations totalled $21.7 million or $0.52 per basic and diluted share. Funds from operations for 2005 totalled $12.0 million or $0.44 and $0.43 per basic and diluted share respectively. For Q4 2006, funds from operations totalled $4.6 million or $0.10 per basic and diluted share. Funds from operations totalled $5.4 million for Q3 2006 and $5.0 million for Q4 2005. The net income for 2006 totalled $45,000 ($0.00 per basic and diluted share) versus net income of $1,669,000 ($0.06 per basic and diluted share) for 2005. Net loss for Q4 2006 totalled $565,000 versus income of $864,000 for the comparative period in 2005.

The following table summarizes the net income on a barrel of oil equivalent basis for the periods indicated.



----------------------------------------------------------------------------
($/boe) Q4 Q4 Q3
2006 2005 2006 2006 2005
----------------------------------------------------------------------------
Sales price $ 48.35 $ 69.02 $ 51.92 $ 50.38 $ 57.04
Royalties 7.51 17.09 10.11 8.95 14.77
Operating expenses 11.51 8.22 8.52 9.28 9.17
Transportation expenses 0.25 0.03 0.14 0.36 0.03
----------------------------------------------------------------------------
Operating netback $ 29.08 $ 43.68 $ 33.15 $ 31.79 $ 33.07
General and administration 2.98 3.86 3.32 2.74 2.98
Interest (income) 1.49 (0.53) 1.67 1.29 (0.06)
Other income - - - (0.16) -
Capital tax (recovery) - 0.69 - - 0.22
----------------------------------------------------------------------------
Cash flow netback $ 24.61 $ 39.66 $ 28.16 $ 27.92 $ 29.93
Depletion, depreciation and
accretion 29.34 26.84 24.88 27.51 20.98
Stock-based compensation 0.52 1.19 0.48 0.44 1.11
Future tax (reduction) (2.35) 4.83 1.16 (0.08) 3.70
----------------------------------------------------------------------------
Net income (loss) $ (2.90) $ 6.80 $ 1.64 $ 0.05 $ 4.14
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The following table provides reconciliations to the change in funds from
operations and net income (loss) for Q4 2006 to Q4 2005 and for the year
2006 to 2005.

----------------------------------------------------------------------------
Q4 2006 to Q4 2005 Year 2006 to Year 2005
Change in Funds from ---------------------------------------------------
Operations and Net Funds from Net Income Funds from
Income (000's) Operations (Loss) Operations Net Income
----------------------------------------------------------------------------
Comparative period $ 4,991 $ 864 $ 11,967 $ 1,669

Increase (decrease) in
revenue:
Change in production
volumes 4,651 4,651 21,947 21,947
Change in prices (4,013) (4,013) (5,248) (5,248)
Change in royalties 710 710 (1,098) (1,098)
Change in other income (181) (181) (83) (83)

(Increase) decrease in
expenses:
Operating (1,195) (1,195) (3,608) (3,608)
Transportation (46) (46) (271) (271)
Interest (177) (177) (832) (832)
Cash general and
administration (89) (89) (958) (958)
Stock-based compensation - 51 - 101
Depletion, depreciation
and accretion - (2,299) - (13,210)
Taxes 88 1,159 88 1,636
Abandonment expenditures (184) - (202) -
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Current period $ 4,555 $ (565) $ 21,702 $ 45
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Capital Expenditures

Midnight had an active 2006 capital program with expenditures totalling approximately $61.8 million, which was more than double our 2005 expenditures (excluding property acquisitions). During 2006, Midnight drilled 33 gross (17.2 net) wells comprised of 18 gross (7.1 net) gas wells, 12 gross (8.0 net) oil wells and 3 gross (2.1 net) dry holes achieving an 88% success rate compared to 2005 where Midnight drilled 13.2 net wells with 100% success. Drilling costs made up the majority of our capital expenditures in 2006 with 42% being directed to the 17.2 net wells. Drilling costs on a per well basis increased over 2005 as all facets of our drilling costs increased and in particular, lease preparation, rig moves and daily rig charges. Average drilling costs in 2006 were $1.5 million per well versus $1.2 million in 2005 despite the average depth of the wells decreasing in 2006. We continued to build our land position in our strategic areas and spent $5.0 million on land additions for 2006. During 2006, facilities, pipelines and equipment comprised 23% of our expenditures up from 10% (net of property acquisitions) in 2005. At our Sheldon area, we spent $6.7 million on facilities to tie in our production with an additional $5.0 million incurred in Red Earth to tie in some existing production to a third party battery as well as to put in place single well batteries.

Midnight has approximately 173,000 net acres of undeveloped land at December 31, 2006. A value of $22.4 million or $130 per acre for undeveloped land and $5.5 million for undeveloped seismic have been excluded from the depletion calculation in the quarter. In 2007, approximately 17 percent of Midnight's net undeveloped acreage will be subject to expiry. The number of acres that actually expire may be reduced through drilling on or adjacent to the expiring lands.

In addition to the cash capital expenditures above, we have capitalized $417,000 of stock-based compensation and the related future tax liability of $179,000 for 2006 consistent with the exploration salaries that we have added to our property base.

For 2007, we have budgeted to reduce capital expenditures to $30 million. Should commodity prices change our capital budget could increase or decrease. Our current 2007 spending will be focused in the Deep Basin (42%) West Central (16%) and Red Earth (36%) with the balance allocated to minor areas.



The following table highlights the breakdown of expenditures by category for
the periods indicated:

----------------------------------------------------------------------------
Capital Expenditures (000's) Q4 Q4 Q3
2006 2005 2006 2006 2005
----------------------------------------------------------------------------
Land $ 99 $ 291 $ 203 $ 4,997 $ 3,564
Property acquisitions - 47,666 - - 47,666
Geological and geophysical 3,371 631 683 6,078 2,117
Drilling 1,726 3,882 8,021 25,865 13,241
Completions 1,619 1,927 2,801 10,316 7,001
Facilities, pipelines and
equipment 1,837 888 1,943 14,477 2,909
Other - - 19 19 9
----------------------------------------------------------------------------
Total expenditures $ 8,652 $ 55,285 $ 13,670 $ 61,752 $ 76,507
----------------------------------------------------------------------------
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Equity

On November 7, 2006, the Company closed a bought deal financing with a syndicate of underwriters and issued 5.5 million common shares at a price of $3.05 per common share to raise gross proceeds of approximately $16.8 million which includes 500,000 common shares issued pursuant to the over-allotment option granted to the underwriters at the same price. Management participated in this issue, acquiring 114,000 shares at $3.05 per share. The offering was done by way of short form prospectus.

On May 17, 2006 Midnight closed a bought deal financing and issued 4 million flow-through common shares at a price of $5.10 per flow-through common share to raise gross proceeds of $20.4 million. Management and service providers participated in this issue acquiring 343,000 shares at $5.10 per flow-through common share. The future tax effect of this issue will be recorded when the company renounces the expenditures in Q1 2007.

During 2006 Midnight issued 2,590,000 stock options, no options were exercised and 53,000 options were forfeited. At December 31, 2006 the Company had outstanding 3,636,800 stock options at an average exercise price of $2.83. At March 21, 2007 the Company had outstanding 47,827,829 common shares, 3,691,800 stock options and 2,083,333 warrants. The average exercise price of the stock options outstanding is $2.82 per share.



----------------------------------------------------------------------------
Share Information (000's) Q4 Q4 Q3
2006 2005 2006 2006 2005
----------------------------------------------------------------------------
Shares outstanding
Basic 47,828 38,328 42,328 47,828 38,328
Diluted 53,548 41,511 45,914 53,548 41,511
Weighted average shares
outstanding
Basic 45,556 30,371 42,328 41,640 27,347
Diluted 45,556 30,862 42,632 41,894 27,696
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Liquidity and Capital Resources

Midnight Oil Exploration Ltd. is listed as a senior issuer on the Toronto Stock Exchange trading under the symbol "MOX". The Company's market capitalization at December 31, 2006 was $113 million.



----------------------------------------------------------------------------
Trading History on the TSX Q4 Q4 Q3
2006 2005 2006 2006 2005
----------------------------------------------------------------------------
High $ 3.38 $ 4.85 $ 4.00 $ 4.70 $ 4.98
Low $ 2.26 $ 3.80 $ 3.00 $ 2.26 $ 3.06
Close $ 2.37 $ 4.42 $ 3.40 $ 2.37 $ 4.42
Volume (000's) 4,505 3,725 1,623 13,429 25,427
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At December 31, 2006, Midnight had drawn $17.9 million on its $30.0 million credit facility and had a working capital deficit of $4.0 million for a net debt position of $21.9 million. Midnight's credit facility is available on a revolving basis until May 31, 2007. On this date and at the Company's discretion, the facility is available on a non-revolving basis for a period of 366 days, at which time the facility would be due and payable. Alternatively, the facility may be extended for a further 364-day period at the request of the Company and subject to approval by the bank. The credit facility bears interest at the bank's prime rate or Bankers' Acceptances plus a stamp based on the Company's debt/cash flow ratio, calculated using the two most recent fiscal quarters. The facility is secured by a $50 million first floating charge debenture and a general securities agreement.

Midnight anticipates that it will have adequate liquidity to fund future working capital and forecasted capital expenditures during 2007 through a combination of cash flow and additional drawing on its existing credit facility. Our 2007 capital budget has been set at $30 million to match our estimated cash flow for the year. Expenditures for our flow-through program should be completed by the end of 2007.

Contractual Obligations



The contractual obligations for which the Company is responsible are as
follows:

----------------------------------------------------------------------------
Less
Contractual than 1-3 4-5 After 5
Obligations (000's) Total 1 Year Years Years Years
----------------------------------------------------------------------------
Flow through share obligation $ 10,100 $ 10,100 $ - $ - $ -
Long-term debt 17,938 - 17,938 - -
Asset retirement obligations 5,862 199 276 195 5,192
----------------------------------------------------------------------------
Total Contractual Obligations $ 33,900 $ 10,299 $ 18,214 $ 195 $ 5,192
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Midnight enters into many contractual obligations in the course of conducting its day to day business. Material contractual obligations consist of our obligation to expend exploration expenditures pursuant to our flow-through share issue on May 17, 2006 and our long-term debt with a major bank. The payment terms on the asset retirement obligation is based on an estimated timing of expenditures to be made in future periods, actual expenditures and when they may occur may differ materially than presented above. Midnight has not entered into any firm transportation commitments to date.

Financial Instruments

Financial instruments comprise cash and cash equivalents, accounts receivable and accounts payable and accrued liabilities. The fair values of these financial instruments approximate their carrying amounts due to their short-term maturities. The Company's long-term debt bears interest at a floating market rate and accordingly the fair market value approximates the carrying value.

Disclosure and Internal Control Procedures

Disclosure and internal control procedures have been designed to ensure that information required to be disclosed by Midnight is accumulated and communicated to the Company's management as appropriate to allow timely decisions regarding required disclosure. An evaluation, based on the work of third party specialists who were engaged to formally document internal controls over financial reporting, was carried out. Midnight's Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation as of the end of the period covered by the annual filings, that the Company's disclosure controls and procedures for the year ended December 31, 2006 are effective to provide reasonable assurance that material information related to Midnight, including its consolidated subsidiaries, is made known to them by others within those entities and the internal controls have been designed over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. It should be noted that while Midnight's Chief Executive Officer and Chief Financial Officer believe that the Company's disclosure and internal control procedures provide a reasonable level of assurance that they are effective, they do not expect that the disclosure and internal control procedures will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Subsequent to the year end and pursuant to the termination of the Administrative and Technical Service Agreement, Midnight has incorporated new internal controls over financial reporting. Effective procedures have been designed and implemented over financial reporting in 2007; however, management is aware that there is a lack of segregation of duties due to the limited number of employees dealing with financial matters. Midnight's Chief Executive Officer, Chief Financial Officer and Vice President Finance have been with the Company since its inception and have extensive industry experience. They are very aware of and actively involved in the Company's on-going operating activities. While there is an inherent weakness in internal controls over financial reporting due to the limited number of staff and the resultant lack of segregation of incompatible duties, the capabilities and involvement of the Chief Executive Officer, Chief Financial Officer and Vice President Finance serve to mitigate this structural weakness. Their efforts, together with the active involvement of the board of directors, are directed to minimize the risk of a material misstatement in financial reporting.

Application of Critical Accounting Estimates

The significant accounting policies used by Midnight are disclosed in note 1 to the audited Consolidated Financial Statements for the years ended December 31, 2006 and 2005. Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Management reviews its estimates on a regular basis. The emergence of new information and changed circumstance may result in actual results or changes to estimated amounts that differ materially from current estimates. The following discussion identifies the critical accounting policies and practices of the Company and helps assess the likelihood of materially different results being reported.

Reserves

Under the National Instrument 51-101 ("NI 51-101") "Proved" reserves are defined as those reserves that can be estimated with a high degree of certainty to be recoverable. The level of certainty should result in at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated Proved reserves. It does not mean that there is a 90% probability that the Proved reserves will be recovered; it means there must be at least a 90% probability that the given amount or more will be recovered.

"Proved plus Probable" reserves are the most likely case and are based on a 50 percent certainty that they will equal or exceed the reserves estimated.

These oil and gas reserve estimates are made using all available geological and reservoir data, as well as historical production data. All of the Company's reserves were evaluated and reported on by an independent qualified reserves evaluator. However, revisions can occur as a result of various factors including: actual reservoir performance, changes in price and cost forecasts or a change in the Company's plans. Reserve changes will impact the financial results as reserves are used in the calculation of depletion and are used to assess whether asset impairment occurs. Reserve changes also affect other non-GAAP measurements such as finding and development costs, recycle ratios and net asset value calculations.

Depletion

The Company follows the full cost method of accounting for oil and natural gas properties. Under this method, all costs related to the acquisition of, exploration for and development of oil and natural gas reserves are capitalized whether successful or not. Depletion of the capitalized oil and natural gas properties and depreciation of production equipment which includes estimated future development costs less estimated salvage values are calculated using the unit-of-production method, based on production volumes in relation to estimated proven reserves.

An increase in estimated proved reserves would result in a reduction in depletion expense. A decrease in estimated future development costs would also result in a reduction in depletion expense.

Unproved Properties

The cost of acquisition and evaluation of unproved properties are initially excluded from the depletion calculation. An impairment test is performed on these assets to determine whether the carrying value exceeds the fair value. Any excess in carrying value over fair value is an impairment. When proved reserves are assigned or a property is considered to be impaired, the cost of the property or the amount of the impairment will be added to the capitalized costs for the calculation of depletion.

Ceiling Test

The ceiling test is a cost recovery test intended to identify and measure potential impairment of assets. An impairment loss is recorded if the sum of the undiscounted cash flows expected from the production of the proved reserves and the lower of cost and market of unproved properties does not exceed the carrying values of the petroleum and natural gas assets. An impairment loss is recognized to the extent that the carrying value exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves and the lower of cost and market of unproved properties. The cash flows are estimated using the future product prices and costs and are discounted using the risk free rate. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material. Any impairment as a result of this ceiling test will be charged to operations as additional depletion and depreciation expense.

Asset Retirement Obligations

The Company records a liability for the fair value of legal obligations associated with the retirement of petroleum and natural gas assets. The liability is equal to the discounted fair value of the obligation in the period in which the asset is recorded with an equal offset to the carrying amount of the asset. The liability then accretes to its fair value with the passage of time and the accretion is recognized as an expense in the financial statements. The total amount of the asset retirement obligation is an estimate based on the Company's net ownership interest in all wells and facilities, the estimated costs to abandon and reclaim the wells and facilities and the estimated timing of the costs to be incurred in future periods. The total amount of the estimated cash flows required to settle the asset retirement obligation, the timing of those cash flows and the discount rate used to calculate the present value of those cash flows are all estimates subject to measurement uncertainty. Any change in these estimates would impact the asset retirement liability and the accretion expense.

Income Taxes

The determination of income and other tax liabilities requires interpretation of complex laws and regulations. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded by management.

Other Estimates

The accrual method of accounting requires management to incorporate certain estimates including estimates of revenues, royalties and operating costs as at a specific reporting date, but for which actual revenues and costs have not yet been received. In addition, estimates are made on capital projects which are in progress or recently completed where actual costs have not been received by the reporting date. The Company obtains the estimates from the individuals with the most knowledge of the activity and from all project documentation received. The estimates are reviewed for reasonableness and compared to past performance to assess the reliability of the estimates. Past estimates are compared to actual results in order to make informed decisions on future estimates.

New Accounting Standards

Financial Instruments - Recognition and Measurement

In April 2005, a series of new accounting standards were released which established guidance for the recognition and measurement of financial instruments. These new standards include Section 1530 "Comprehensive Income", Section 3855 "Financial Instruments - Recognition and Measurement", and Section 3865 "Hedges". The new standards also resulted in a number of consequential amendments to other accounting standards to accommodate the new sections. The standards require all applicable financial instruments to be classified into one of several categories including: financial assets and financial liabilities held for trading, held-to-maturity investments, loans and receivables, available-for-sale financial assets, or other financial liabilities. The financial instruments are then included on a company's balance sheet and measured at fair value, at cost or amortized cost, depending on the classification. Subsequent measurement and recognition of changes in value of the financial instruments depends on the initial classification. These standards are effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2006 and must be implemented simultaneously. Midnight is adopting these standards on January 1, 2007. Midnight is currently assessing the impact of these standards on the financial statements.

Internal Control Reporting

The Canadian Securities Administrators decided not to proceed with the proposed multilateral instrument 52-111 Reporting on Internal Control over Financial Reporting and instead proposed to expand proposed multilateral instrument 52-109 Certificate of Disclosure in Issuers' Annual and Interim Filings. The major changes resulting from this is the CEO and CFO will be required to certify in the annual certificates that they have evaluated the effectiveness of internal controls over financial reporting ("ICOFR") as of the end of the financial year and disclose in the annual MD&A their conclusion about the effectiveness of ICOFR. There will be no requirement to obtain an internal control audit opinion from the issuer's auditors concerning management's assessment of the effectiveness of ICOFR. There is also no requirement to design and evaluate internal controls against a suitable control framework. This proposed amendment is expected to apply for the year ended December 31, 2008. Midnight is continuing with its evaluation of ICOFR to ensure it meets the criteria for the proposed certification deadline.

Risk Factors

There are a number of risk factors facing Companies that participate in the Canadian oil and gas industry. A summary of risk factors relating to our business are provided in the Risk Factors Section of our Annual Information Form filed on SEDAR.

Additional Information

Additional information relating to Midnight is filed on SEDAR and can be viewed at www.sedar.com. Information can also be obtained by contacting the Company at Midnight Oil Exploration Ltd., 2100, 144 4th Ave S.W., Calgary, Alberta T2P 3N4 or by email to ir@midnightoil.ca or by accessing our website at www.midnightoil.ca.



CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Balance Sheets
As at December 31,

(000's)

---------------------------------------------------------------------------
2006 2005
---------------------------------------------------------------------------

Assets
Current assets:
Accounts receivable $ 5,928 $ 6,259
Deposits and prepaid expenses 189 80
---------------------------------------------------------------------------
6,117 6,339

Future taxes (note 6) 391 -

Petroleum and natural gas assets (note 2) 146,325 104,832

---------------------------------------------------------------------------
$ 152,833 $ 111,171
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable and accrued liabilities $ 10,153 $ 11,096

Long-term debt (note 3) 17,938 11,973

Future taxes (note 6) - 229

Asset retirement obligations (note 4) 1,930 1,416

Shareholders' equity:
Share capital (note 5) 119,807 84,262
Warrants (note 5) 42 42
Contributed surplus (note 5) 1,234 469
Retained earnings 1,729 1,684
---------------------------------------------------------------------------
122,812 86,457

Commitments (note 8)
---------------------------------------------------------------------------
$ 152,833 $ 111,171
---------------------------------------------------------------------------
---------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.

On behalf of the Board:

Signed "Tom Medvedic" Signed "Paul Moynihan"
Director Director


Consolidated Statements of Income and Retained Earnings
Years ended December 31,

(000's, except per share amounts)

----------------------------------------------------------------------------
2006 2005
----------------------------------------------------------------------------

Revenues:
Petroleum and natural gas sales $ 39,688 $ 22,989
Royalties (7,051) (5,953)
Other income 128 211
----------------------------------------------------------------------------
32,765 17,247

Expenses:
Operating 7,305 3,697
Transportation 282 11
Interest 1,019 187
General and administration (note 5 (f)) 2,508 1,651
Depletion, depreciation and accretion 21,666 8,456
----------------------------------------------------------------------------
32,780 14,002

----------------------------------------------------------------------------
Income (loss) before taxes (15) 3,245

Taxes: (note 6)
Capital tax - 88
Future tax (reduction) (60) 1,488
----------------------------------------------------------------------------
(60) 1,576

Net income 45 1,669

Retained earnings, beginning of year 1,684 15

----------------------------------------------------------------------------
Retained earnings, end of year $ 1,729 $ 1,684
----------------------------------------------------------------------------

Income per share: (note 5)
Basic $ - $ 0.06
Diluted $ - $ 0.06
----------------------------------------------------------------------------


See accompanying notes to consolidated financial statements.


Consolidated Statements of Cash Flows
Years Ended December 31,

(000's)

----------------------------------------------------------------------------
2006 2005
----------------------------------------------------------------------------
Cash provided by (used in):

Operations:
Net income $ 45 $ 1,669
Items not involving cash:
Depletion, depreciation and accretion 21,666 8,456
Stock-based compensation 348 449
Future tax (redudction) (60) 1,488
Abandonment expenditures (297) (95)
----------------------------------------------------------------------------
21,702 11,967
Changes in non-cash working capital 3,558 (4,697)
----------------------------------------------------------------------------
25,260 7,270

Financing:
Issue of common shares 37,175 48,000
Share issue costs (2,369) (3,092)
Increase in long-term debt 5,965 11,973
Changes in non-cash working capital 77 91
---------------------------------------------------------------------------
40,848 56,972

Investments:
Petroleum and natural gas additions (61,752) (28,841)
Property acquisition - (47,666)
Changes in non-cash working capital (4,356) 7,234
---------------------------------------------------------------------------
(66,108) (69,273)

----------------------------------------------------------------------------
Changes in cash - (5,031)
Cash, beginning of year - 5,031
----------------------------------------------------------------------------
Cash, end of year $ - $ -
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Taxes paid $ 88 $ -
Interest paid $ 1,016 $ 154
----------------------------------------------------------------------------


Cash is defined as cash and cash equivalents.

See accompanying notes to consolidated financial statements


Notes to Consolidated Financial Statements

For the years ended December 31, 2006 and 2005
(Tabular amounts are stated in thousands of dollars except share and
per share amounts)


Nature of operations:

The principal business of the Company is the exploration for, exploitation, development and production of oil and natural gas reserves. All activity is conducted in Western Canada and comprises a single business segment.

Certain prior period figures have been reclassified to conform with current period presentation.

1. Significant accounting policies:

The consolidated financial statements of the Company have been prepared in accordance with Canadian generally accepted accounting principles. The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and revenues and expenses during the reporting period. Actual results could differ from those estimated.

Specifically, the amounts recorded for depletion, depreciation and accretion of petroleum and natural gas assets and asset retirement obligations are based on estimates. The ceiling test is based on estimates of reserves, production rates, oil and gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be significant.

(a) Consolidation:

The consolidated financial statements include the accounts of Midnight Oil Exploration Ltd. and its wholly owned subsidiary, Midnight Oil Resources Ltd. and a partnership, Midnight Oil Exploration Partnership. All inter-entity transactions and balances have been eliminated.

(b) Cash and cash equivalents:

Cash and cash equivalents are comprised of cash and all investments with a maturity date of three months or less.

(c) Petroleum and natural gas assets:

(i) Capitalized costs:

The Company follows the full cost method of accounting for petroleum and natural gas assets. Under this method, all costs related to the acquisition of, exploration for and development of petroleum and natural gas reserves are capitalized. These costs include land acquisition costs, geological and geophysical expenditures, rentals and other carrying charges on undeveloped properties, costs of drilling both productive and non-productive wells, oil and gas production equipment and facilities, asset retirement costs and administration expenses directly related to the acquisition, exploration and development activities. Proceeds from the disposition of oil and natural gas properties are accounted for as a reduction of capitalized costs, with no gain or loss recognized, unless such disposition would result in a change greater than 20% in the depletion or depreciation.

(ii) Depletion and depreciation:

Depletion of petroleum and natural gas assets and depreciation of production equipment are calculated using the unit-of-production method, based on production volumes before royalties in relation to estimated proven reserves as determined by an independent petroleum engineering firm. Natural gas reserves and production are converted to equivalent barrels of oil based upon the relative energy content of six thousand cubic feet of gas to one barrel of oil.

The cost of acquisition and evaluation of unproved properties are initially excluded from the depletion calculation. A separate impairment test is performed on these assets to determine whether the carrying value exceeds the fair value. Any excess in carrying value over fair value is an impairment. When proved reserves are assigned or a property is considered to be impaired, the cost of the property or the amount of the impairment will be added to the capitalized costs for the calculation of depletion.

Other assets are depreciated on a declining balance basis at rates ranging from 20% to 35%.

(iii) Ceiling test:

Petroleum and natural gas assets are evaluated in each reporting period to determine that the carrying amount is recoverable and does not exceed the fair value of the properties.

The carrying amounts are assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves, the lower of cost and market of unproved properties and the cost of major development projects exceeds the carrying amount of the cost centre. When the carrying amount is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying amount of the cost centre exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves, the lower of cost and market of unproved properties and the cost of major development projects of the cost centre. The cash flows are estimated using expected future product prices and costs and are discounted using a risk-free interest rate.

(d) Asset retirement obligations:

The Company recognizes the asset retirement obligations for the future cost associated with removal, site restoration and asset retirement costs. The fair value of the liability for the Company's asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using the Company's credit adjusted risk-free interest rate and the corresponding amount recognized by increasing the carrying amount of petroleum and natural gas assets. The asset recorded is depleted on a unit of production basis over the life of the reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to earnings in the period. Revisions to the estimated timing of cash flows or to the original estimated undiscounted cost could also result in an increase or decrease to the obligation. Actual costs incurred upon settlement of the retirement obligation are charged against the obligation to the extent of the liability recorded.

(e) Joint interest operations:

Substantially all of the Company's exploration, development and production activities related to oil and gas operations are conducted jointly with others and accordingly the accounts reflect only the Company's proportionate interest in such activities.

(f) Revenue recognition:

Revenue from the sale of petroleum and natural gas is recognized during the month when title passes to a third party.

(g) Income taxes:

The Company uses the asset and liability method of tax allocation accounting. Under this method, future tax assets and liabilities are determined based on differences between the financial reporting and tax bases of assets and liabilities, and measured using the substantially enacted tax rates and laws that will be in effect when the differences are expected to reverse.

(h) Stock-based compensation plans:

The Company applies the fair value method for valuing stock option grants and warrants. Under this method, compensation cost attributable to all share options granted and warrants issued are measured at fair value at the grant and issuance date and expensed over the vesting period with a corresponding increase to contributed surplus. Upon the exercise of the stock options and warrants, consideration received together with the amount previously recognized in contributed surplus is recorded as an increase to share capital.

(i) Per share information:

Basic per share information is computed by dividing income by the weighted average number of common shares outstanding for the period. The treasury stock method is used to determine the diluted per share amounts, whereby any proceeds from the stock options, warrants or other dilutive instruments are assumed to be used to purchase common shares at the average market price during the period. The weighted average number of shares outstanding is then adjusted by the net change.

(j) Flow-through shares:

The resource expenditure deductions for income tax purposes related to exploratory activities funded by flow-through shares are renounced to investors in accordance with tax legislation. Future tax liabilities and share capital are adjusted by the estimated cost of the renounced tax deductions when the expenditures are renounced.



2. Petroleum and natural gas assets:

----------------------------------------------------------------------------
2006 2005
----------------------------------------------------------------------------

Cost $ 176,594 $ 113,567
Accumulated depletion and depreciation (30,269) (8,735)
----------------------------------------------------------------------------
$ 146,325 $ 104,832
----------------------------------------------------------------------------
----------------------------------------------------------------------------


During the year ended December 31, 2006, the Company capitalized $2,733,000 (2005 - $1,627,000) of general and administration expenses related to exploration and development activities. Included in this amount is the non-cash related stock-based compensation of $417,000. The future tax liability of $179,000 associated with the capitalized stock-based compensation has also been capitalized.

The cost of unproven properties at December 31, 2006 of $27,905,000 (2005 - $24,895,000) has been excluded from the depletion and depreciation calculation. Future development costs of proven reserves of $6,197,000 (2005 - $9,911,000) have been included in the depletion and depreciation calculation.

On November 29, 2005, Midnight closed a property acquisition for a purchase price of $47,666,000. The acquisition had an effective date of October 1, 2005. As part of the acquisition, Midnight assumed asset retirement obligations of $707,000. This acquisition was completed in connection with Daylight's acquisition of the outstanding shares of Tempest Energy Corp. which closed on November 30, 2005.

At December 31, 2006, the Company applied a ceiling test to its petroleum and natural gas assets using expected future market prices of:



----------------------------------------------------------------------------
WTI Oil AECO Gas USD$/CAD$
Year ($US/bbl) (CDN$/mmbtu) Exchange Rates
----------------------------------------------------------------------------
2007 62.00 7.20 0.87
2008 60.00 7.45 0.87
2009 58.00 7.75 0.87
2010 57.00 7.80 0.87
2011 57.00 7.85 0.87
2012 57.50 8.15 0.87
2013 58.50 8.30 0.87
2014 59.75 8.50 0.87
2015 61.00 8.70 0.87
2016 62.25 8.90 0.87
2017 63.50 9.10 0.87
Thereafter +2.0% +2.0% 0.87
----------------------------------------------------------------------------
----------------------------------------------------------------------------


3. Long-term debt:

Midnight has a revolving term credit facility available up to $30 million with a Canadian chartered bank. The facility is available on a revolving basis until May 31, 2007. On May 31, 2007, at the Company's discretion, the facility is available on a non-revolving basis for a period of 366 days, at which time the facility would be due and payable. Alternatively, the facility may be extended for a further 364-day period at the request of the Company and subject to approval by the bank. The credit facility bears interest at the bank's prime rate or at Bankers' Acceptance rates plus a stamping fee based on the Company's debt to cash flow ratio, calculated using the two most recent fiscal quarters. The facility is secured by a $50 million first floating charge debenture and a general securities agreement. At December 31, 2006, $17,938,000 was drawn on this facility. The effective interest rate for the bank debt was 5.4% for the year ended December 31, 2006. The $30 million borrowing base is subject to a semi-annual and annual review by the bank.

4. Asset retirement obligations:

The Company's asset retirement obligations result from net ownership interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities. The Company estimates the total undiscounted amount of cash flow required to settle its asset retirement obligations is approximately $5,862,000 (2005 - $3,950,000) which will be incurred from 2007 to 2054. The majority of the costs will be incurred between 2010 and 2020. An inflation factor of 2% has been applied to the estimated asset retirement cost at December 31, 2006. A credit-adjusted risk-free rate of 8% was used to calculate the fair value of the asset retirement obligations at December 31, 2006.

A reconciliation of the asset retirement obligations is provided below:



----------------------------------------------------------------------------
2006 2005
----------------------------------------------------------------------------

Balance, beginning of year $ 1,416 $ 542
Liabilities incurred 679 215
Acquired on property acquisition (note 2) - 707
Liabilities settled (297) (95)
Accretion expense 132 47
----------------------------------------------------------------------------
Balance, end of year $ 1,930 $ 1,416
----------------------------------------------------------------------------
----------------------------------------------------------------------------


5. Share capital

(a) Authorized:

The authorized share capital consists of an unlimited number of common shares without par value.



(b) Issued and outstanding:

----------------------------------------------------------------------------
Number of
Shares Amount
----------------------------------------------------------------------------

Common shares:
Balance, December 31, 2004 26,327,829 $ 38,240
Issued pursuant to private placement 12,000,000 48,000
Share issue costs (net of tax of $1,114) - (1,978)
----------------------------------------------------------------------------
Balance, December 31, 2005 38,327,829 $ 84,262
Issued pursuant to private placement 4,000,000 20,400
Issued pursuant to short form prospectus 5,500,000 16,775
Share issue costs (net of tax of $739) - (1,630)
----------------------------------------------------------------------------
Balance, December 31, 2006 47,827,829 $ 119,807
----------------------------------------------------------------------------
----------------------------------------------------------------------------


On November 7, 2006 the Company issued 5,500,000 Common Shares at a price of $3.05 per share. The proceeds, net of share issue cost of $1.1 million ($0.7 million net of tax), were $15.7 million.

On May 17, 2006 the Company issued 4,000,000 flow-through Common Shares at a price of $5.10 per share. The proceeds, net of share issue costs of $1.3 million ($0.9 million net of tax), were $19.1 million.

On November 30, 2005, the Company issued 12,000,000 Common Shares at a price of $4.00 per share. The proceeds, net of share issue cost of $3.1 million ($2.0 million net of tax), were $44.9 million.

(c) Per share amounts:

The following summarizes the common shares used in calculating per share amounts:



----------------------------------------------------------------------------
2006 2005
----------------------------------------------------------------------------

Weighted average shares outstanding:
Basic 41,640,158 27,347,007
Diluted 41,893,925 27,695,819
----------------------------------------------------------------------------


The reconciling items between basic and diluted average common shares outstanding are stock options and warrants. At December 31, 2006 there were 1,606,800 (2005-1,174,300) options that were anti-dilutive.

(d) Stock options:

The Company has reserved 4,782,783 common shares for granting under option to employees, directors and other persons who provide ongoing management or consulting services to the Company. Stock options are granted for a term up to five years and vest over three years from the date granted. The exercise price of each option equals the market price of the Company's common shares on the date of the grant.

The summary of stock option activity is presented below:



----------------------------------------------------------------------------
Number of Weighted average
options exercise price
----------------------------------------------------------------------------

Balance, December 31, 2004 - $ -
Granted 1,174,300 3.49
Forfeited (74,500) 3.30
----------------------------------------------------------------------------
Balance, December 31, 2005 1,099,800 $ 3.50
Granted 2,590,000 2.56
Forfeited (53,000) 3.49
----------------------------------------------------------------------------
Balance, December 31, 2006 3,636,800 $ 2.83
----------------------------------------------------------------------------

Exercisable at December 31, 2006 352,267 $ 3.50
----------------------------------------------------------------------------


The following table summarizes information about the stock options outstanding at December 31, 2006:



----------------------------------------------------------------------------
Options Outstanding Options Exercisable
----------------------------------------------------------------------------
Weighted
Weighted average Weighted
Range of average remaining average
exercise Number exercise contractual Number exercise
price outstanding price life (years) exercisable price
----------------------------------------------------------------------------

$ 2.00-2.99 2,130,000 $ 2.37 4.9 - $ -
$ 3.00-3.99 1,364,300 3.42 3.7 304,767 3.40
$ 4.00-4.99 142,500 4.13 3.9 47,500 4.13
----------------------------------------------------------------------------
3,636,800 $ 2.83 4.4 352,267 $ 3.50
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(e) Warrants:

----------------------------------------------------------------------------
Number of
Warrants Amount
----------------------------------------------------------------------------

Warrants:
Balance, December 31, 2004 2,333,333 $ 47
Forfeited (250,000) (5)
----------------------------------------------------------------------------
Balance December 31, 2005 and 2006 2,083,333 $ 42
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Each warrant is exercisable into one common share of the Company at a price of $3.00 per share. The warrants vest equally over three years and expire on November 29, 2008. Two thirds of the warrants have vested and are exercisable at December 31, 2006.

(f) Stock-based compensation:

Midnight accounts for its stock-based compensation plan using the fair value method. Under this method, a compensation cost is charged over the vesting period for warrants and options granted to employees, officers, directors and other service providers.

Midnight has not incorporated an estimated forfeiture rate for stock options that will not vest, rather the Company accounts for actual forfeitures as they occur.

The fair value of options and warrants granted were estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions and resulting values:



----------------------------------------------------------------------------
2006 2005
----------------------------------------------------------------------------

Fair value of options granted $ 0.95 $ 1.31
Risk free interest 4.0% 3.7%
Estimated hold period prior to exercise 4 years 4 years
Expected volatility 40% 40%
Dividend per share $ 0.00 $ 0.00
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(g) Contributed surplus:

The following table reconciles Midnight's contributed surplus:

----------------------------------------------------------------------------
2006 2005
----------------------------------------------------------------------------

Balance, beginning of year $ 469 $ 15
Stock-based compensation 765 449
Cancellation of warrants - 5
----------------------------------------------------------------------------
Balance, end of year $ 1,234 $ 469
----------------------------------------------------------------------------
----------------------------------------------------------------------------


6. Taxes:

The provision for taxes in the financial statement differs from the result that would have been obtained by applying the combined federal and provincial tax rate to the Company's income (loss) before taxes. The difference results from the following items:



----------------------------------------------------------------------------
2006 2005
----------------------------------------------------------------------------

Income (loss) before taxes $ (15) $ 3,245
----------------------------------------------------------------------------

Combined federal and provincial tax rate 34.5% 37.6%

Computed "expected" tax expense (recovery) $ (5) $ 1,221

Increase (decrease) in taxes resulting from:
Non-deductible crown charges 765 1,263
Resource allowance (889) (980)
Stock-based compensation 120 168
Other (77) (152)
Effect of change in tax rate 26 (32)
----------------------------------------------------------------------------
Future tax (reduction) (60) 1,488

Capital tax - 88
----------------------------------------------------------------------------
Taxes $ (60) $ 1,576
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The future tax liability (asset) at December 31 is comprised of the tax effect of temporary differences as follows:



----------------------------------------------------------------------------
2006 2005
----------------------------------------------------------------------------

Petroleum and natural gas assets $ 1,397 $ 1,847
Asset retirement obligations (560) (496)
Non-capital losses - (165)
Attributed Canadian Royalty Income (79) (91)
Share issue costs (1,149) (866)
----------------------------------------------------------------------------
Balance, December 31 $ (391) $ 229
----------------------------------------------------------------------------
----------------------------------------------------------------------------


7. Related party:

Midnight and Daylight Energy Ltd. ("Daylight") operated under an Administrative and Technical Services Agreement which provided for the sharing of services required to manage Midnight's activities and govern the allocation of general and administration expenses between the entities. Under this agreement, Daylight had been the employer on behalf of the parties and received payment for certain technical and administrative services provided to Midnight. Effective December 31, 2006 the existing Administrative and Technical Services Agreement has been terminated. Technical personnel including: geologists, geophysicists, engineers, land negotiators, business development and land contracts personnel are currently functioning independently and are now direct charges of Midnight. Certain services in the areas of land administration, drilling and completion operations, marketing, certain accounting and human resources and administration continued to be transitioned for the fourth quarter. Certain services between Daylight and Midnight that are administrative, provide reasonable economy and do not involve competitive issues will continue beyond 2006 through a direct cost arrangement. Pursuant to the Administrative and Technical Services Agreement and for the year ended December 31, 2006 $1,810,000 (2005 - $995,000) of fees were charged relating to general and administration activities and $1,939,000 (2005 - $1,627,000) of fees were charged relating to capital expenditures.

As a result of this arrangement, the majority of the Company's accounts receivable and accounts payable at December 31, 2006 and 2005 are due from (to) Daylight. Payment terms are in accordance with normal industry standards.

8. Commitments

The Company renounced $20.4 million of qualifying oil and natural gas expenditures effective December 31, 2006 pursuant to the flow-through share offering which closed on May 17, 2006. By December 31, 2006, the Company had incurred $10.3 million of qualifying expenditures and has an additional commitment to expend $10.1 million on qualifying expenditures by December 31, 2007.

9. Risk management

(a) Credit risk:

Portions of the Company's accounts receivable are with joint venture partners in the oil and gas industry and are subject to normal industry credit risks. Purchasers of the Company's oil and natural gas products are subject to an internal credit review designed to mitigate the risk of non-payment.

(b) Commodity price risk:

There were no financial instruments in place to manage commodity prices during the period ended December 31, 2006.

(c) Foreign currency:

While substantially all of the Company's sales are denominated in Canadian dollars, the market prices in Canada for oil and natural gas are impacted by changes in the exchange rate between the Canadian and United States dollar.

(d) Fair value of financial instruments:

Financial instruments comprise cash and cash equivalents, accounts receivable and accounts payable and accrued liabilities. The fair values of these financial instruments approximate their carrying amounts due to their short-term maturities. The Company's long-term debt bears interest at a floating market rate and accordingly the fair market value approximates the carrying value.

(e) Interest rate risk:

The Company is exposed to interest rate risk to the extent that changes in market interest rates will impact the Company's cash and cash equivalents that have a floating interest rate. The bank facility is also based on a floating interest rate. The Company had no interest rate swaps or hedges at December 31, 2006.

Contact Information

  • Midnight Oil Exploration Ltd.
    Fred Woods
    President and Chief Executive Officer
    (403) 303-8505
    (403) 264-0085 (FAX)
    Email: fwoods@midnightoil.ca
    or
    Midnight Oil Exploration Ltd.
    Judy Stripling
    Executive Vice President and Chief Financial Officer
    (403) 303-8502
    (403) 264-0085 (FAX)
    Email: jstripling@midnightoil.ca
    Website: www.midnightoil.ca