CALGARY, April 20 /CNW/ - Pine Cliff Energy Ltd. (www.pinecliffenergy.com) (TSX VENTURE:PNE) is pleased to announce its financial and operational results for the three months and fiscal year ended December 31, 2006. Much of the year's efforts were directed towards activities in South America. Staffing and becoming familiar with regulations and business philosophies in both Argentina and Chile were necessary prior to proceeding with the acquisition of properties.
These efforts are now being rewarded. In Q1, 2007, Pine Cliff's 93 percent owned subsidiary, CanAmericas Energy Ltd. ("CanAmericas"), was successful in negotiating two major farm-in arrangements in Argentina. One has been completed and the other is subject to completion of CanAmericas due diligence. The farm-ins will result in earning interests in a total of 912,810 gross acres (542,410 net acres) of exploration and exploitation lands. For more details kindly refer to "Property Discussions" of this report. Negotiations are ongoing with regard to the acquisition of additional exploration, exploitation and producing properties.
The Company is pleased with the progress that CanAmericas is making in South America. The geological potential and size of these concessions is extraordinary. A land position of this magnitude is extremely difficult to obtain and provides the potential for a large number of drill locations.
In 2007 Pine Cliff will also increase its activities in Canada. The focus will be to acquire production and to participate in more drilling.
HIGHLIGHTS
2006 2005(1)
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Financial
Revenue - Oil and Gas $ 661,100 $ 633,873
Funds flow from Operations(2) (424,248) 368,259
Per Share Basic (0.01) 0.01
Per Share Fully Diluted (0.01) 0.01
Net Loss (1,014,605) (329,062)
Per Share Basic (0.03) (0.01)
Per Share Fully Diluted (0.03) (0.01)
Capital Expenditures and Acquisitions 271,926 2,097,930
Shareholders' Equity 4,239,638 5,110,407
Shares Outstanding (December 31) 36,523,041 36,420,041
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Operations
Oil and Liquids (barrels per day) 5 7
Average Price ($ per barrel) 63.88 62.42
Natural Gas (MCF per day) 195 175
Average Price ($ per MCF) 7.58 10.78
Total Barrels per Day (BOE per day)(3) 38 36
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Reserves(4)
Oil and Liquids (barrels)
Proved Developed Producing (Gross) 10,200 13,300
Proved plus Probable (Gross) 13,700 21,400
Natural Gas (MCF)
Proved Developed Producing (Gross) 326,000 352,000
Proved plus Probable (Gross) 440,000 568,000
Share Trading Statistics
Share Prices (based on daily closing price)
High $ 0.76 $ 0.61
Low $ 0.40 $ 0.42
Close $ 0.65 $ 0.55
Daily Average Trading Volume 3,754 7,535
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(1) Operations commenced April 8, 2005
(2) Funds flow from operations is not a recognized measure under GAAP.
Management believes that in addition to net earnings, funds flow from
operations is a useful supplemental measure as it demonstrates the
Company's ability to generate the cash necessary to fund future
growth through capital investment. Investors are cautioned, however,
that this measure should not be construed as an indication of the
Company's performance. The Company's method of calculating this
measure may differ from other issuers and accordingly, it may not be
comparable to that used by other issuers. For these purposes, the
Company defines funds flow from operations as funds provided by
operations before changes in non-cash operating working capital items
excluding foreign exchange loss and asset retirement expenditures.
(3) BOE's are calculated using a conversion ratio of 6 MCF to 1 barrel of
oil. The conversion is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent
a value equivalency at the wellhead and as such may be misleading if
used in isolation.
(4) Gross reserves relate to the Company's ownership of reserves before
royalty interests.
REVIEW OF OPERATIONS
Reserves
The Company engaged the services of Sproule Associates Limited to prepare
a reserve evaluation with an effective date of December 31, 2006. The reserves
are located in the Province of Alberta. The majority of the Company's
production is comprised of natural gas. The Company's main gas producing area
is located in the Sundance area of West Central Alberta. The gross reserve
figure in the following charts represents the Company's ownership interest
before royalties and the net figure is after deductions for royalties.
SUMMARY OF OIL AND GAS RESERVES
AS OF DECEMBER 31, 2006
FORECAST PRICES AND COSTS
RESERVES
Natural Natural Gas
Gas Liquids
Gross Net Gross Net
RESERVE CATEGORY (MMcf) (MMcf) (Mbbl) (Mbbl)
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PROVED
Developed Producing 326 249 10 7
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TOTAL PROVED 326 249 10 7
PROBABLE 114 87 4 2
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TOTAL PROVED PLUS PROBABLE 440 336 14 9
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RECONCILIATION OF COMPANY GROSS RESERVES
BY PRINCIPAL PRODUCT TYPE
FORECAST PRICES AND COSTS
Natural
Gas
Gross Proved Gross Probable Gross Proved
(MMcf) (MMcf) Plus Probable
(MMcf)
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December 31, 2005 352 216 568
Technical Revisions 45 (102) (57)
Production (71) - (71)
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December 31, 2006 326 114 440
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SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE
AS OF DECEMBER 31, 2006
FORECAST PRICES AND COSTS
NET PRESENT VALUE OF FUTURE NET REVENUE
After Income Taxes
Discounted at (%/year)
0 5 10 15 20
(M$)
RESERVE CATEGORY
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PROVED
Developed Producing 1,722 1,519 1,362 1,237 1,135
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TOTAL PROVED 1,722 1,519 1,362 1,237 1,135
PROBABLE 483 346 258 200 161
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TOTAL PROVED PLUS PROBABLE 2,205 1,865 1,620 1,437 1,296
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Year Edmonton Par Alberta Gas Propane Butane Pentane
Price Reference
Price
Plantgate
(Cdn $ (Cdn $ (Cdn $ (Cdn $ (Cdn $
per barrel) per MCF) per barrel) per barrel) per barrel)
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2007 74.10 7.51 43.94 55.23 75.88
2008 77.62 8.38 46.03 57.85 79.49
2009 70.25 7.55 41.66 52.36 71.94
2010 65.56 7.37 38.88 48.87 67.14
2011 61.90 7.54 36.71 46.14 63.40
2012 63.15 7.68 37.45 46.07 64.67
2013 64.42 7.79 38.21 48.02 65.98
2014 65.72 7.93 38.97 48.98 67.30
2015 67.04 8.07 39.76 49.97 68.66
2016 68.39 8.21 40.56 50.97 70.04
2017 69.76 8.35 41.38 52.00 71.45
Natural gas and liquid prices escalate at various rates thereafter.
The following cautionary statements are specifically required by NI
51-101.
- It should not be assumed that the estimates of future net revenue
presented in the above tables represent the fair market value of the
reserves. There is no assurance that the forecast prices and costs
assumptions will be attained and variances could be material.
- Disclosure provided herein in respect of BOE's may be misleading,
particularly if used in isolation. In accordance with NI 51-101, a BOE
conversion ratio of 6mcf:1bbl has been used in all cases in this
disclosure. This BOE conversion ratio is based on an energy
equivalency conversion method primarily applicable at the burner tip
and does not represent a value equivalency at the wellhead.
- Estimates of reserves and future net revenues for individual
properties may not reflect the same confidence level as estimates of
reserves and future net revenues for all properties due to the effects
of aggregation.
Land Holdings
The Company's holdings of natural gas leases and rights as of December 31,
2006 are as follows:
2006 2005
Gross Acres Net Acres Gross Acres Net Acres
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Alberta 7,360 2,802 7,680 2,844
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Petroleum and Natural Gas Capital Expenditures
The following table summarizes petroleum and natural gas capital
expenditures incurred by the Company on acquisitions, land, seismic,
exploration and development drilling and production facilities for the years
ended December 31:
2006 2005
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Exploration and development costs $ 226,193 $ 1,089,632
Acquisitions - 999,701
Land costs - 5,490
Seismic - 2,433
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Net petroleum and natural gas capital
expenditures $ 226,193 $ 2,097,256
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Drilling History
The following table summarizes the Company's gross and net drilling
activity and success:
2006
Development Exploratory Total
Gross Net Gross Net Gross Net
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Natural Gas 1 0.1 - - 1 0.1
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Success rate 100% 100% - - 100% 100%
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2005
Development Exploratory Total
Gross Net Gross Net Gross Net
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Natural Gas 2 0.2 - - 2 0.2
Dry - - 1 1.0 1 1.0
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Total 2 0.2 1 1.0 3 1.2
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Success rate 100% 100% - - 67% 16.7%
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PROPERTY DISCUSSIONS
Pine Cliff's only producing property is located in the Sundance area of West Central Alberta. The Company has a 13.7% average working interest in 5,280 acres (723 net) of Crown land in the area. There are currently 5 (0.53 net) wells producing. The wells produce from multiple zones from the Cadomin to the Belly River. Current production from the five wells is approximately 2,660 mcf/day gross, 305 mcf/day net to Pine Cliff. NGL's are produced in association with the natural gas.
There is still significant industry activity in the Sundance area. With the success of last year's drilling program the interests in non producing properties are being analyzed to determine whether there are additional prospective drilling locations. The increased activity in the area has caused bottlenecks in non-interest gathering systems and gas plants causing some of our wells to be shut-in from time to time over the last year. Increases in facility capacity and re-routing of a portion of our production have alleviated these problems at this time.
In 2006 Pine Cliff had decided to pursue oil and gas opportunities in South America. In 2007, the Company has been successful in negotiating two separate farm-in agreements to acquire an interest in 40 gross townships (912,810 acres) (net 24 townships (542,410 acres)) of land.
Canadon Ramirez Farm-In
The Company through its 93 percent owned subsidiary, CanAmericas Energy Ltd. ("CanAmericas") has earned a 49% interest in 47,940 gross acres (23,490 net acres) of an exploitation concession situated in the western part of the San Jorge Basin by committing to fund 100% of exploration costs totaling $US 5,500,000 over the next two years. The commitment includes conducting a 3D seismic program and drilling three wells in the first year at an estimated cost of $US 4,630,000. In the second year of the commitment CanAmericas is committed to spend the remainder of the $US 5,500,000 on drilling.
The acreage is bordered by several producing oil fields. Over 40 separate prospective reservoirs belonging to the Upper-Mid Cretaceous-aged Bajo Barreal and Castillo Formations, are known to exist within the farm in area at depths between 1950 - 5000 feet. Additionally, Neocomian aged source rocks within the farm in area have been proven to be oil generating and over pressured.
CanAmericas is currently conducting a 75 square mile 3D seismic survey which is to be completed by the end of May. It is the first such program to be recorded over the producing and earned areas that will permit detailed stratigraphic and structural mapping of multiple leads that were initially developed from existing 2D coverage. An agreement was made with an adjacent operator to trade seismic data providing us with data over a total of 93 square miles. This will allow CanAmericas to tie in its seismic data to seismic conducted over an existing producing oil field. A drilling rig has been contracted and drilling of three prospects is scheduled to begin by August, 2007.
San Jorge Basin Farm-In
The Company through its 93 percent owned subsidiary, CanAmericas, has negotiated exclusive rights to progressively earn a 60% interest in 864,870 gross acres (518,920 net acres) of an exploration permit situated in the north-central San Jorge basin. CanAmericas has the right to become operator of the Permit and will likely decide to do so after it has completed its due diligence.
Subject to completion of the due diligence, the exclusive rights commit CanAmericas to fund 100% of the costs to conduct an aero-magnetic and aero-gravity survey over the entire permit area, acquire 39 square miles of 3D seismic, and drill two exploration wells to earn a 30% participating interest in the entire permit. The surveys are to be completed within one year of the effective date of the agreement and the wells are to be drilled within two years of the effective date.
CanAmericas will earn an additional 30% in the entire permit by drilling two additional wells within three years of the effective date of the agreement. CanAmericas will receive 100 percent of cash flow from this property until it has recovered 100 percent of its costs for the two work programs. The estimated cost for both work programs is $US 4,620,000. After completion of the two work programs costs will be shared on a 60 percent CanAmericas and 40 percent farmor basis.
Principal reservoir objectives are multiple sands of the Upper-Mid Cretaceous Bajo Barreal and Castillo Formations which are known to exist throughout the permit at depths ranging between 1000 - 5000 feet. A producing oil field lies adjacent to the southern border of this permit and existing seismic data and well control suggests the productive trend may extend into the southern portion of this permit. Additionally, numerous oil and gas shows encountered by older wells drilled throughout the permit during the 1960's - 1980's prove that the permit contains an active hydrocarbon system.
CanAmericas will initially acquire the regional aero-gravity and aero-magnetic surveys over the entire permit and with this information, and existing well and 2D seismic coverage, will determine where to best conduct the required 3D seismic survey. The 3D coverage is expected to assist in better understanding strategraphic environments that were previously identified from existing 2D seismic coverage.
FINANCIAL AND OPERATIONAL
The Company was incorporated in the Province of Alberta on November 10, 2004 and commenced operations on April 8, 2005.
Quarterly Financial and Operational Highlights
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2006
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4th 3rd 2nd 1st
Revenue - Oil
and Gas $ 170,231 $ 90,386 $ 108,413 $ 292,070
Funds Flow from
Operations(1) (51,833) (113,095) (337,020) 77,700
Per Share Basic (0.00) (0.00) (0.01) 0.00
Per Share Diluted (0.00) (0.00) (0.01) 0.00
Net Loss (209,575) (211,784) (526,107) (67,139)
Per Share Basic (0.01) (0.01) (0.01) (0.00)
Per Share Diluted (0.01) (0.01) (0.01) (0.00)
Capital Expenditures
and Acquisitions 19,227 (3,463) 124,236 131,926
Total Assets 4,494,010 4,700,305 4,892,079 5,373,147
Working Capital 2,963,513 3,030,822 3,175,577 3,625,133
Shareholder's Equity 4,239,638 4,411,915 4,589,015 5,093,951
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Operations
Oil and Liquids
(barrels per day) 3 5 4 9
Natural Gas (MCF
per day) 226 131 139 284
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(1) Funds flow from operations is not a recognized measure under GAAP.
Management believes that in addition to net earnings, funds flow from
operations is a useful supplemental measure as it demonstrates the
Company's ability to generate the cash necessary to fund future
growth through capital investment. Investors are cautioned, however,
that this measure should not be construed as an indication of the
Company's performance. The Company's method of calculating this
measure may differ from other issuers and accordingly, it may not be
comparable to that used by other issuers. For these purposes, the
Company defines funds flow from operations as funds provided by
operations before changes in non-cash operating working capital items
excluding foreign exchange loss and asset retirement expenditures.
Production
----------
On April 8, 2005, with an effective date of January 1, 2005, the Company acquired interests in two natural gas properties for a cash payment of $999,701. The Sundance land, located in West Central Alberta was the major property acquired. Pine Cliff acquired a 13.2 percent working interest (subject to Crown royalty) in 4,320 acres in this area. There are two wells (0.308 net) on these lands that have been producing for approximately two years. Two additional multi-zone wells were drilled in 2005 (net 0.2) and a further well (0.038 net) was drilled in 2006. In 2006 production averaged 195 MCF (2005 - 175 MCF) of natural gas and five barrels (2005 - 7 barrels) of natural gas liquids per day.
During the second quarter of 2006, the operator of the gas plant, where approximately 80 percent of the Company's production is processed, performed an annual turnaround resulting in the significant reduction in production for that period. Subsequent to the completion of the turnaround, capacity restrictions resulted in the continued shut-in of the Company's production. In September the capacity restrictions were resolved and the Company's production resumed.
Pine Cliff also acquired a 100 percent interest in a 256 hectare Crown lease in the Auburndale area of East Central Alberta. The Company drilled a Devonian well for sweet natural gas during 2005. The Company tested the well and concluded that the projected production volume is not sufficient to construct a five kilometer pipeline to tie it in. The drilling and land costs were written off in 2005.
Revenue
-------
Revenue from petroleum and natural gas sales for 2006 was $661,100 compared to $633,873 in 2005. The increase of $27,227 was due to higher production volumes offset by lower commodity prices. Average price received in 2006 for its natural gas was $7.58 (2005 - $10.78) per MCF and $63.88 (2005 - $62.42) per barrel for natural gas liquids. The Company did not have hedging agreements in either 2006 or 2005 and presently does not have any future hedging agreements.
Fourth quarter petroleum and natural gas sales increased to $170,231 from $90,386 in the third quarter. The increase is due to full production from the Sundance property as well as higher natural gas prices.
Royalties
---------
Royalties consist of Crown royalties paid to the Province of Alberta and gross overriding royalties. In 2006 the Company recorded a net recoverable amount of $1,054 in Crown royalties compared to a Crown royalty expense of $17,464 in 2005. The operator of the Sundance property applied for and received a Crown royalty holiday in respect of the wells drilled in 2005. As customary in the industry, Crown royalties were paid on this well until the royalty holiday was granted. As a result of the Crown royalty holiday, the Company recovered in 2006 the full amount of the $17,464 paid in 2005. The royalty holiday has expired in 2006 and the Company is now paying royalties on this production.
Gross overriding royalties of $26,723 (2005 - $21,366) were recorded in 2006. There has been no significant change to the rates over the two years or quarter over quarter.
Interest Income
---------------
The Company maintains an investment account with its principal banker that pays interest at prime less 2.25 percent as long as the Company maintains a minimum balance of $1,500,000. The Company in March 2007 drew down on the outstanding cash balance to finance its seismic expenditure commitment in Argentina. Please refer to Business Prospects Section.
Production Costs
----------------
Production costs for the year ended December 31, 2006, were $132,346 (2005 - $53,449) or $9.62 (2005 - $5.41) per BOE (Q4 - $10.90 per BOE, Q3 - $9.37 per BOE). BOE's are calculated using a conversion ratio of 6 MCF to 1 barrel of oil. The conversion is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead and as such may be misleading if used in isolation. Due to capacity constraints at the gas plant, the Company is incurring increased processing fees in relation to its Sundance gas production.
General and Administrative
--------------------------
General and administrative expenses for 2006 were $1,043,866 (Q4 - $254,226) compared to $239,417 for 2005 and $220,442 for the third quarter of 2006. The primary reason for the increase in 2006 expenses was due to the Company incurring $621,621 in administration costs related to its activities in South America. The majority of the South American costs related to engineering and consulting fees of $408,651, travel and accommodation costs of $92,121, and legal costs of $96,559.
Pine Cliff does not have any employees at the present time but has engaged Comstate Resources Ltd. ("Comstate") a related party (see Related Party section), to provide management services and engages the services of consultants on a contract or temporary basis. Pine Cliff's subsidiary CanAmericas Energy Ltd. ("CanAmericas") has also engaged the services of two individual professionals as senior management and officers of CanAmericas.
In addition to the above South American costs, increases in geological consulting fees of $18,490 (Canadian operations); audit, accounting and engineering costs of $65,874 for year end audit and financial reporting and $84,000 in management fees (see Related Party section) were incurred in 2006.
Stock Based Compensation
------------------------
Stock based compensation for the year ended December 31, 2006, was $128,385 (2005 - $87,041). The Company has a stock-based compensation plan for Pine Cliff. The Company records a compensation expense over the vesting period based on the fair value of options granted to employees, directors and consultants. The Company issued 895,000 stock options in Pine Cliff during 2006. The Company estimated the stock options fair value at $191,458 ($0.21 per option) using the Black-Scholes option pricing model, assuming a weighted average risk free interest rate of 4.13 percent, weighted average expected volatility of 63.1 percent, weighted average expected life of 2.5 years and no annual dividend rate.
Dry Hole Exploration Costs
--------------------------
As previously discussed, the Company drilled a Devonian gas well in the second quarter of 2005. The well, although capable of production, did not contain sufficient reserves to warrant a five kilometer pipeline. Given the lack of current economics for this well, no proved or probable reserves were assigned to the well in the preparation of the third party engineering report. With the Company following the successful efforts method of accounting (see below), capital costs associated with each field that are in excess of that field's economic value are to be written off. As such the Company wrote off $6,222 (2005 - $588,256) in respect of the cost of the land and development costs incurred in drilling the Devonian well.
Depletion, Depreciation and Amortization
----------------------------------------
The Company follows the successful efforts method of accounting for petroleum and natural gas properties and related equipment. Costs of acquiring unproved properties are capitalized. When petroleum and natural gas properties are found to contain proved reserves as determined by Company engineers, the related net book value is depleted on the unit-of-production basis, calculated by field. The costs of dry holes and abandoned properties are charged to operations. Geological costs, lease rentals and carrying costs are charged to income as incurred. Costs of drilling exploratory and development wells that result in additions to proved reserves are capitalized and depleted on the unit-of-production basis. Tangible equipment is depreciated on a straight-line basis over ten years.
Provisions are made for asset retirement obligations through the recognition of the fair value of obligations associated with the retirement of tangible long-life assets being recorded in the period the asset is put into use, with a corresponding increase to the carrying amount of the related asset. The obligations recognized are statutory, contractual or legal obligations. The liability is adjusted over time for changes in the value of the liability through accretion charges which are included in depletion, depreciation and accretion expense. The costs capitalized to the related assets are amortized to earnings in a manner consistent with the depletion and depreciation of the underlying asset.
At December 31, 2006, the estimated total undiscounted amount required to settle the asset retirement obligations was $71,031 (2005 - $42,796). These obligations will be settled based on the useful lives of the underlying assets, which extend up to 13 years into the future. This amount has been discounted using a credit-adjusted risk-free interest rate of five percent. The discount rate is reviewed annually and adjusted if considered necessary. A change in the rate would not have a significant impact on the amount recorded for asset retirement obligations.
The calculation of the above requires an estimation of the amount of the Company's petroleum reserves by field. This figure is calculated annually by an independent engineering firm and used to calculate depletion. This calculation is to a large extent subjective. Reserve adjustments are affected by economic assumptions as well as estimates of petroleum products in place and methods of recovering those reserves. To the extent reserves are increased or decreased, depletion costs will vary.
Income Taxes
------------
The Company follows the liability method of accounting for income taxes under which the income tax provision is based on the temporary differences in the accounts calculated using income tax rates expected to apply in the year in which the temporary differences will reverse. The Company has sufficient tax pools so it is not liable for current income tax in 2006. Due to the decline in natural gas prices as well as the moderate decrease in estimated reserves, the ability to claim the tax benefits of the following tax pools is no longer more likely than not and as such the Company has recorded a full valuation allowance to eliminate the future tax asset.
Non-Controlling Interest
------------------------
As described above, Foreign Corp. owns seven percent of CanAmericas. The $38,701 of loss applicable to non-controlling interest relates to their share of revenues and costs associated with CanAmericas' South American activities.
Loss
----
The loss for the 2006 fiscal year is $1,014,605 ($209,575 in the fourth quarter) compared to $329,062 in 2005 and $211,784 in the third quarter of 2006. The 2006 loss was predominantly due to general and administrative costs incurred in respect of the Company's South American operations as well as a future tax adjustment. Please see Business Prospects Section for discussions regarding future activities.
Funds Flow from Operations
--------------------------
Funds flow from operations decreased to negative $424,248 in 2006 from a positive $368,259 in 2005. The decrease from the 2005 amount was mainly due to the Company's activities in South America. Quarter over quarter saw a reduction in the funds flow loss due to increased funds flow from the Company's oil and natural gas operations.
The following reconciliation compares funds flow for the fiscal years ended December 31, 2006 and 2005 to the Company's cash flow from operating activities as calculated according to Canadian generally accepted accounting principles:
2006 2005 ------------------------------------------------------------------------- Cash flow from operating activities ($ 168,809) $ 25,764 Items not affecting funds flow Due from related party (16,006) 16,006 Accounts receivable (154,329) 339,329 Prepaid expenses (806) 3,460 Accounts payable and accrued liabilities (117,138) (16,135) Due to related party 165 (165) Asset retirement obligations settled 35,123 - Foreign exchange loss (2,448) - ------------------------------------------------------------------------- Funds flow for the period ($ 424,248) $ 368,259 -------------------------------------------------------------------------
Liquidity and Capital Resources
-------------------------------
As of December 31, 2006, Pine Cliff had positive working capital of $2,963,513 (December 31, 2005 - $3,565,689). These funds will be used to fund financial commitments as discussed under Property Discussion. The Company plans on financing the balance of its commitments through the issue of additional common shares and company cash flow.
Forward-Looking Information
---------------------------
Certain information set forth in this document, including management's assessment of Pine Cliff Energy Ltd. ("Pine Cliff" or "the Company") future plans and operations, contains forward-looking statements. By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond Pine Cliff's control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility and ability to access sufficient capital from internal and external sources. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Pine Cliff's actual results, performance or achievement could differ materially from those expressed in, or implied by these forward-looking statements, and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that Pine Cliff will derive therefrom. Pine Cliff disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Readers are cautioned that net present value of reserves does not represent fair market value of reserves.
The TSX Venture Exchange does not accept responsibility for the adequacy
or accuracy of this release.
Pine Cliff Energy Ltd.
Consolidated Balance Sheets
As at December 31
2006 2005
Assets
Current
Cash $ 2,915,020 $ 3,334,961
Due from related party (Note 2) - 16,006
Accounts receivable 185,001 339,330
Prepaid expenditures 2,654 3,460
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3,102,675 3,693,757
Future Income Tax Asset (Note 4) - 216,254
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Property and Equipment (Note 5)
Property and equipment 1,848,887 1,538,809
Accumulated depletion and depreciation (457,552) (180,832)
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1,391,335 1,357,977
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$ 4,494,010 $ 5,267,988
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Liabilities
Current
Accounts payable and accrued liabilities $ 139,162 $ 127,903
Due to related party (Note 2) - 165
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139,162 128,068
Asset Retirement Obligations (Note 6) 40,240 29,513
Non-controlling Interests (Note 3) 74,970 -
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254,372 157,581
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Commitments (Notes 8 and 11)
Shareholders' Equity
Share capital (Note 7) 5,377,343 5,352,428
Contributed surplus 205,962 87,041
Deficit (1,343,667) (329,062)
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4,239,638 5,110,407
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$ 4,494,010 $ 5,267,988
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Pine Cliff Energy Ltd.
Consolidated Statements of Loss and Deficit
For the years ended December 31
2006 2005
Revenue
Oil and gas sales $ 661,100 $ 633,873
Royalties (25,669) (38,830)
Alberta royalty tax credits - 4,366
Interest income 118,981 61,715
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754,412 661,124
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Expenses
Production costs 132,346 53,449
General and administrative 1,043,866 239,417
Foreign exchange loss 2,448 -
Stock based compensation 128,385 87,041
Dry hole exploration costs (Note 5) 6,222 588,256
Depletion, depreciation and accretion 278,197 181,208
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1,591,464 1,149,371
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Loss Before Income Taxes and
Non-controlling Interests (837,052) (488,247)
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Income Taxes Provision (Recovery) (Note 4)
Current - -
Future 216,254 (159,185)
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216,254 (159,185)
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Loss before Non-Controlling Interests (1,053,306) (329,062)
Loss applicable to non-controlling interests
(Note 3) 38,701 -
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Loss for the Year (1,014,605) (329,062)
Deficit, beginning of year (329,062) -
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Deficit, end of year $(1,343,667) $ (329,062)
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Loss Per Share - Basic and Diluted (Note 7) $ (0.03) $ (0.01)
Pine Cliff Energy Ltd.
Consolidated Statements of Cash Flow
For the years ended December 31
2006 2005
Operating Activities
Loss for the year $(1,014,605) $ (329,062)
Items not affecting cash
Stock based compensation 128,385 87,041
Dry hole exploration costs 6,222 588,256
Depletion, depreciation and accretion 278,197 181,208
Foreign exchange loss 2,448 -
Future income taxes (recovery) 216,254 (159,185)
Loss applicable to non-controlling
interests (38,701) -
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(421,800) 368,258
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Change in non-cash working capital
Due from related party 16,006 (16,006)
Accounts receivable 154,329 (339,328)
Prepaid expenditures 806 (3,460)
Accounts payable and accrued liabilities 117,138 16,135
Due to related party (165) 165
Asset retirement obligations settled (35,123) -
-------------------------------------------------------------------------
252,991 (342,494)
-------------------------------------------------------------------------
Cash Provided by (Used in) Operating Activities (168,809) 25,764
-------------------------------------------------------------------------
Financing Activities
Share option proceeds 15,450 -
Issue of shares by subsidiary to
non-controlling interests 113,670 -
Proceeds received on initial
public offering - 5,463,005
Issue costs - (88,802)
Change in non-cash working capital
Accounts payable and accrued liabilities - (25,000)
Due to related party - (53,845)
-------------------------------------------------------------------------
Cash Provided by Financing Activities 129,120 5,295,358
-------------------------------------------------------------------------
Investing Activities
Property and equipment expenditures (271,926) (2,097,930)
Change in non-cash working capital
Accounts payable and accrued liabilities (105,878) 111,768
-------------------------------------------------------------------------
Cash Used In Investing Activities (377,804) (1,986,162)
-------------------------------------------------------------------------
Foreign Exchange Loss on Cash Held in
Foreign Currency (2,448) -
-------------------------------------------------------------------------
Net Cash Inflow (Outflow) (419,941) 3,334,960
Cash, Beginning of Year 3,334,961 1
-------------------------------------------------------------------------
Cash, End of Year $ 2,915,020 $ 3,334,961
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash Interest Paid $ - $ -
Cash Taxes Paid $ - $ -
Notes to the Financial Statements
For the Years Ended December 31, 2006 and 2005
1. SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The consolidated financial statements have been prepared by
management in accordance with Canadian generally accepted accounting
principles as described below.
Consolidation
These financial statements include the accounts of the Company and
its 93 percent owned subsidiary CanAmericas Energy Ltd.
("CanAmericas") (see note 3). Inter-company transactions and balances
are eliminated upon consolidation.
Measurement Uncertainty
The preparation of the consolidated 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 consolidated financial statements
and revenues and expenses during the reporting period. Actual results
can differ from those estimates.
In particular, amounts recorded for depreciation and depletion and
amounts used in ceiling test calculations are based on estimates of
petroleum and natural gas reserves and future costs required to
develop those reserves. The Company's reserve estimates are evaluated
annually by an independent engineering firm. By their nature, these
estimates of reserves and the related future cash flows are subject
to measurement uncertainty, and the impact on the consolidated
financial statements of future periods could be material.
The amounts recorded for asset retirement obligations were estimated
based on the Company's net ownership interest in all wells and
facilities, estimated costs to abandon and reclaim the wells and
facilities and the estimated period during which these costs will be
incurred in the future. Any changes to these estimates could change
the amount recorded for asset retirement obligations and may
materially impact the consolidated financial statements of future
periods.
Petroleum and Natural Gas Properties and Related Equipment
The Company follows the successful efforts method of accounting for
petroleum and natural gas properties and related equipment. Costs of
exploratory wells are initially capitalized pending determination of
proved reserves. Costs of wells which are assigned proved reserves
remain capitalized, while costs of unsuccessful wells are charged to
earnings. All other exploration costs including geological and
geophysical costs are charged to earnings as incurred. Development
costs, including the cost of all wells, are capitalized.
Producing properties and significant unproved properties are assessed
annually or as economic events dictate, for potential impairment.
Impairment is assessed by comparing the estimated net undiscounted
future cash flows to the carrying value of the asset. If required,
the impairment recorded is the amount by which the carrying value of
the asset exceeds its fair value.
Depreciation and depletion of capitalized costs of oil and gas
producing properties are calculated using the unit of production
method. Development and exploration drilling and equipment costs are
depleted over the remaining proved developed reserves. Depreciation
of other plant and equipment is provided on the straight line method.
Straight line depreciation is based on the estimated service lives of
the related assets which is estimated to be ten years.
Furniture, Equipment and Other
These assets are recorded at cost and are depreciated on a straight
line basis over five to ten years.
Income Taxes
The Company follows the liability method of accounting for income
taxes under which the income tax provision is based on the temporary
differences between the amounts reported by the Company and their
respective tax bases calculated using income tax rates expected to
apply in the year in which the temporary differences will reverse.
Asset Retirement Obligations
The Company recognizes the fair value of obligations associated with
the retirement of long-life assets in the period the asset is put
into use, with a corresponding increase to the carrying amount of the
related asset. The obligations recognized are statutory, contractual
or legal obligations. The liability is adjusted over time for changes
in the value of the liability through accretion charges which are
included in depletion, depreciation and accretion expense. The costs
capitalized to the related assets are amortized to earnings in a
manner consistent with the depletion and depreciation of the
underlying asset.
Stock-based Compensation
The Company has a stock-based compensation plan which is described in
Note 7. The Company records compensation expense over the vesting
period based on the fair value of options granted to employees,
directors and consultants. These amounts are recorded as contributed
surplus. Any consideration paid by employees, directors or
consultants on the exercise of these options is recorded as share
capital together with the related contributed surplus associated with
the exercised options.
Revenue Recognition
Petroleum and natural gas sales are recognized when the commodities
are delivered and title transfers to the purchasers.
Foreign Currency Translation
The Company translates foreign currency denominated monetary assets
and liabilities of its integrated foreign subsidiary at the exchange
rate in effect at the balance sheet date and non-monetary assets and
liabilities are translated at historical exchange rates. Revenues and
expenses are translated at estimated transaction date exchange rates
except depletion and depreciation expense, which is translated at the
same historical exchange rates as the related assets. Exchange gains
or losses are included in the determination of net income as foreign
exchange gain or loss.
Joint Interest Operations
Significant portions of the Company's oil and gas operations are
conducted with other parties and accordingly the financial statements
reflect only the Company's proportionate interest in such activities.
Earnings Per Share
Basic earnings per share is computed by dividing the earnings by the
weighted average number of shares outstanding during the year.
Diluted per share amounts reflect the potential dilution that could
occur if options to purchase common shares were exercised. The
treasury stock method is used to determine the dilutive effect of
common share options, whereby proceeds from the exercise of common
share options or other dilutive instruments are assumed to be used to
purchase common shares at the average market price during the year.
2. RELATED PARTY TRANSACTIONS
Bonterra Energy Income Trust ("Bonterra"), an organization with
common directors and management and the former parent of the Company,
through its wholly owned subsidiaries Comstate Resources Ltd.
("Comstate"), Bonterra Energy Corp. ("Bonterra Corp.") and Novitas
Energy Ltd. ("Novitas") has provided working capital, management
services and has sold natural gas properties to the Company. Fees
paid for management services totalled $216,000 (2005 - $132,000) for
the year. The management services agreement may be cancelled by the
Company with 90 days notice.
As of December 31, 2006, the Company owed Nil (2005 - $165) to
Bonterra and its wholly owned subsidiaries for these items. The
Company has an account receivable from Novitas of Nil (December 31,
2005 - $16,006) relating to post closing adjustments in relation to
the natural gas properties acquired.
3. NON-CONTROLLING INTERESTS
The Company incorporated a subsidiary company, CanAmericas, to
explore and develop oil and gas properties primarily in South
America. CanAmericas is owned 93.3 percent by the Company and
6.7 percent by a foreign private corporation ("Foreign Corp.").
CanAmericas was initially financed by investments of $1,400,000 U.S.
for 5,600,000 common shares from the Company and $100,000 U.S. for
400,000 common shares from Foreign Corp.
Foreign Corp. has been granted an option to acquire an additional
1,000,000 common shares of CanAmericas at $0.25 U.S. per common
share. The options vest 50 percent on each of January 13, 2007 and
January 13, 2008 and expire on January 13, 2011.
4. INCOME TAXES
The Company recorded a future income tax asset in 2005 as at that
time management considered its recoverability to be more likely than
not. As of December 31, 2006, it was determined that this criteria
was not met and as such the entire amount of the future income tax
asset was fully offset by a valuation allowance.
2006 2005
Amount Amount
---------------------------------------------------------------------
Future income tax assets:
Capital assets $ 125,932 $ 158,295
Asset retirement obligation 11,670 10,454
Share issue costs 29,171 47,505
Loss carry-forward (expires 2016) 215,798 -
Valuation allowance (382,571) -
---------------------------------------------------------------------
$ - $ 216,254
---------------------------------------------------------------------
Income tax expense differs from the amounts that would be computed by
applying Canadian federal and provincial income tax rates as follows:
2006 2005
---------------------------------------------------------------------
Loss before income taxes and
non-controlling interests $ (837,052) $ (488,247)
Combined federal and provincial income
tax rates 34.5% 37.6%
---------------------------------------------------------------------
Income tax provision calculated using
statutory tax rates (288,783) (183,679)
Increase (decrease) in income taxes
resulting from:
Stock based compensation 44,293 32,745
Non-deductible crown royalties 329 4,667
Resource allowance (4,854) (19,059)
Change in valuation allowance 382,571 -
Change in tax rates 84,195 -
Other (1,497) 6,141
---------------------------------------------------------------------
Income tax provision (recovery) $ 216,254 $ (159,185)
---------------------------------------------------------------------
---------------------------------------------------------------------
The Company has the following tax pools, which may be used to reduce
taxable income in future years, limited to the applicable rates of
utilization:
Rate of
Utilization
% Amount
---------------------------------------------------------------------
Undepreciated capital costs 25 $ 305,936
Canadian oil and gas property expenditures 10 728,371
Canadian development expenditures 30 398,588
Canadian exploration expenditures 100 392,110
Share issue costs 20 100,588
Non-capital loss carryforward (expire 2016) 100 757,797
---------------------------------------------------------------------
$ 2,683,390
---------------------------------------------------------------------
---------------------------------------------------------------------
5. PROPERTY AND EQUIPMENT
2006 2005
Accumulated Accumulated
Depletion and Depletion and
Cost Depreciation Cost Depreciation
-------------------------------------------------------------------------
Undeveloped land $ 5,538 $ - $ 5,490 $ -
Petroleum and
natural gas
properties and
related equipment 1,797,586 450,365 1,533,319 180,832
Furniture,
equipment and
other 45,763 7,187 - -
-------------------------------------------------------------------------
$ 1,848,887 $ 457,552 $ 1,538,809 $ 180,832
-------------------------------------------------------------------------
-------------------------------------------------------------------------
On April 8, 2005, the Company purchased its original properties from
Bonterra (see Note 2) for approximately $1,000,000 in cash, with an
effective date of January 1, 2005. The properties included one
producing property and some exploration lands. The transaction was
concluded between the related parties at fair value.
In 2006, the Company wrote off $6,222 (2005 - $588,256) in respect of
the cost of the land and exploration costs incurred in drilling an
exploratory well. The well, although capable of production, does not
contain sufficient reserves to warrant tie-in. Given the lack of
current economics for this well, no proved or probable reserves were
assigned to the well in the preparation of the third party
engineering report.
6. ASSET RETIREMENT OBLIGATIONS
At December 31, 2006, the estimated total undiscounted amount
required to settle the asset retirement obligations was $71,031
(December 31, 2005 - $42,796). Costs for asset retirement have been
calculated assuming a 5 percent inflation rate for 2007, 4 percent
for 2008, 3 percent for 2009 and 2 percent thereafter. These
obligations will be settled based on the useful lives of the
underlying assets, which extend up to 13 years into the future. This
amount has been discounted using a credit-adjusted risk-free interest
rate of 5 percent.
Changes to asset retirement obligations were as follows:
2006 2005
---------------------------------------------------------------------
Asset retirement obligations, December 31 $ 29,513 $ -
Obligations associated with acquisition
and development programs - 29,138
Adjustment to asset retirement obligation 44,375 -
Liabilities settled during the year (35,123) -
Accretion 1,475 375
---------------------------------------------------------------------
Asset retirement obligations, December 31 $ 40,240 $ 29,513
---------------------------------------------------------------------
---------------------------------------------------------------------
7. SHARE CAPITAL
Authorized
Unlimited number of Common Shares without nominal or par value.
Unlimited number of Class B Preferred Shares without nominal or par
value which may be issued in one or more series.
2006 2005
Issued Number Amount Number Amount
-------------------------------------------------------------------------
Common Shares
Balance, beginning
of year 36,420,041 $ 5,352,428 10 $ 1
Issued pursuant to
public offering - - 36,420,031 5,463,005
Share issue costs - - - (167,647)
Issued on exercise
of stock options 103,000 15,450 - -
Transfer of
contributed
surplus to share
capital - 9,465 - -
Future tax benefit
of share issue
costs - - - 57,069
-------------------------------------------------------------------------
Balance,
end of year 36,523,041 $ 5,377,343 36,420,041 $ 5,352,428
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The number of common shares used to calculate diluted loss per share
for the year ended December 31, 2006 is 36,477,619 (December 31, 2005
- 27,545,132). The exercise of outstanding stock options would have
no dilutive effect on per share amounts.
On April 7, 2005, the Company concluded its initial public offering
of 36,420,031 Common Shares at $0.15 per share for gross proceeds of
$5,463,005. The Company granted 930,000 stock options to its
directors and officers, and an additional 802,000 stock options to
other service providers at an exercise price of $0.15 per share. The
Company commenced trading on the TSX Venture Exchange on April 11,
2005.
The Company may grant options for up to 3,605,583 (2005 - 3,605,583)
common shares. The exercise price of each option granted equals the
market price of the common share on the date of grant and the
options' maximum term is five years.
A summary of the status of the Company's stock option plan as of
December 31, 2006 and December 31, 2005, and changes during the years
ended on those dates are presented below:
December 31, 2006 December 31, 2005
-------------------------------------------------------------------------
Weighted- Weighted-
Average Average
Exercise Exercise
Options Price Options Price
-------------------------------------------------------------------------
Outstanding at
beginning of year 1,686,000 $ 0.16 - $ 0.00
Options granted 895,000 0.52 1,752,000 0.16
Options exercised (103,000) 0.15 -
Options cancelled (58,000) 0.21 (66,000) 0.15
-------------------------------------------------------------------------
Outstanding at end
of year 2,420,000 $ 0.29 1,686,000 $ 0.16
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Options exercisable
at end of year 740,000 $ 0.16 - $ 0.00
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Options Outstanding Options Exercisable
-------------------------------------------------------------------------
Weighted-
Average Weighted- Weighted-
Range of Number Remaining Average Number Average
Exercise Outstanding Contractual Exercise Exercisable Exercise
Prices At 12/31/06 Life Price At 12/31/06 Price
-------------------------------------------------------------------------
$0.15 1,515,000 3.1 years $0.15 730,000 $0.15
0.50 - 0.60 825,000 3.1 years 0.50 10,000 0.59
0.70 - 0.75 80,000 3.1 years 0.72 - -
-------------------------------------------------------------------------
$0.15 - 0.75 2,420,000 3.1 years $0.29 740,000 $0.16
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The Company records compensation expense over the vesting period
based on the fair value of options granted to employees, directors
and consultants. Unvested options as of December 31, 2006 vest
872,500 in 2007 and 807,500 in 2008.
The Company issued 895,000 stock options with an estimated fair value
of $191,458 ($0.21 per option) using the Black-Scholes option pricing
model with the following key assumptions in 2006:
Weighted-average risk free interest rate (%) 4.13
Dividend yield (%) 0.00
Expected life (years) 2.5
Weighted-average volatility (%) 63.1
8. COMMITMENTS
Commencing February 1, 2005, the Company entered into a management
agreement with Comstate (see Note 2). The management agreement
consists of a monthly fee of $18,000 (2005 - $12,000) per month plus
out of pocket costs, a fee of three percent of net earnings before
income taxes, $250 per month per operated producing well and $150 per
month per water injector well.
For commitments entered into subsequent to December 31, 2006 please
see Note 11.
9. FINANCIAL INSTRUMENTS
Fair Values
The Company's financial instruments included in the balance sheet are
comprised of due from related party, accounts receivable and current
liabilities. The fair values of these financial instruments
approximate their carrying value due to the short-term maturity of
those instruments.
Credit Risk
Substantially all of the Company's accounts receivable are due from
customers in the oil and gas industry and are subject to normal
industry credit risks. The carrying value of accounts receivable
reflects management's assessment of associated credit risks.
Commodity Price Risk
The Company's operations and financial results may be affected by
fluctuations in commodity prices and exchange rates.
Currency Risk
The Company is exposed to fluctuations in foreign currency as a
result of its South American operations. The Company has not entered
into any foreign currency derivatives with respect to this exposure.
10. SEGMENTED INFORMATION
The Company, with the incorporation of CanAmericas in February, 2006,
has operations in Canada and South America; all operating activities
are related to exploration, development and production of petroleum
and natural gas as follows:
South
($) Canada America Total
Twelve Months Ended
December 31, 2006(1)
Revenue, gross 729,332 50,749 780,081
Loss before non-controlling
interest 472,797 580,509 1,053,306
Property and equipment 1,352,759 38,576 1,391,335
Capital expenditures 226,163 45,763 271,926
Total assets 3,254,440 1,239,570 4,494,010
(1) Prior to the incorporation of CanAmericas all of the Company's
operations were in Canada and as such no prior period
information has been provided.
11. SUBSEQUENT EVENT - COMMITMENT
Subsequent to December 31, 2006, the Company entered into two farm-in
agreements in South America which require future expenditure
commitments as outlined below:
Canadon Ramirez Concession
Pine Cliff through its 93 percent owned subsidiary, CanAmericas, has
committed to pay 100% of costs totaling $5,500,000 US, including the
21% Value Added Tax ("V.A.T."), for work to be conducted on the
concession within two years to earn a 49% participating interest.
Commitment by Year ($000's US)
Year Amount
---- ------
2007 4,630
2008 870
------
5,500
------
------
San Jorge Basin Permit
Pine Cliff through its 93 percent owned subsidiary, CanAmericas, has
committed to pay 100% of costs totalling $4,620,000 US including
V.A.T. to earn a 60% participating interest in the entire permit.
Commitment by Year ($000's US)
Year Amount
---- ------
2007 300
2008 2,595
2009 1,725
------
4,620
------
------
%SEDAR: 00021536E