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| Share Name | Share Symbol | Market | Type |
|---|---|---|---|
| Sierra Vista Energy Ltd Com Npv Class B | TSXV:SVR.B | TSX Venture | Ordinary Share |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 0.00 | - |
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NOT FOR DISTRIBUTION IN THE UNITED STATES NEWSWIRE SERVICES OR FOR DISSEMINATION
IN THE UNITED STATES.
Sierra Vista Energy Ltd. (TSX VENTURE:SVR.A) (TSX VENTURE:SVR.B) ("Sierra Vista"
or the "Company") today announces that it has filed its unaudited financial
statements and management's discussion and analysis for the three months ended
June 30, 2007. Select operational and financial results are outlined below and
should be read in conjunction with the Company's unaudited interim financial
statements and related MD&A which can be found on Sedar at www.sedar.com.
Financial and Operational Comments Include the Following:
- Production averaged 309 boe/d for the first six months of 2007 as compared to
139 boe/d in the first six months of 2006, representing a 124% increase.
Production suffered from a number of the Company's wells being shut in for a
period of 22 days during the quarter due to a third party compressor failure and
scheduled plant maintenance;
- Revenue increased 128% in the first six months of 2007 to $3,036,968 from
$1,330,327 for the first six months of 2006;
- Cash flow increased to $717,879 in the first six months of 2007 from $649,141
in the first quarter of 2006, an increase of 11%, year over year.
----------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Financial
Petroleum and natural
gas revenue $ 1,295,008 655,831 $ 3,036,968 $ 1,330,327
Cash flow from
operations $ 22,806 $ 294,709 $ 717,879 $ 649,141
Per share - basic $ 0.00 $ 0.02 $ 0.02 $ 0.04
Per share - diluted $ 0.00 $ 0.02 $ 0.02 $ 0.03
Net income (loss) $ (780,683) $ 578,792 $ (1,120,583) $ 667,996
Per share - basic $ (0.02) $ 0.03 $ (0.03) $ 0.04
Per share - diluted $ (0.02) $ 0.03 $ (0.03) $ 0.03
Capital expenditures $ 667,561 $ 6,333,803 $ 5,081,612 $12,525,492
Working capital
deficiency, including
bank debt $(1,152,780) $(3,818,763)$ (1,152,780) $(3,818,763)
Total assets $42,605,686 $21,865,189 $ 42,605,686 $21,865,189
Operating
Crude oil and natural
gas liquids (bbl/d) 122 63 145 57
Natural gas (mcf/d) 839 466 985 491
Barrels of oil
equivalent (boe/d) (6:1) 262 141 309 139
----------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Average Prices
Crude oil and natural gas
liquids ($/bbl) $ 62.99 $ 66.30 $ 62.20 $ 64.77
Natural gas ($/mcf) $ 7.77 $ 6.54 $ 7.91 $ 7.43
Barrels of oil equivalent
($/boe) $ 54.26 $ 51.33 $ 54.35 $ 52.87
Field operating netback
per boe $ 24.49 $ 35.22 $ 29.73 $ 36.00
Weighted average shares
outstanding 41,676,950 18,486,298 39,916,242 18,424,088
Actual Class A Shares
outstanding at end of
period 29,976,950 9,555,000 29,976,950 9,555,000
Actual Class B Shares
outstanding at end of
period 1,170,000 1,170,000 1,170,000 1,170,000
----------------------------------------------------------------------------
Outlook
Sierra Vista continues to assemble properties and opportunities in the Peace
River Arch area of Alberta. Management is reviewing Sierra Vista's current
operations and plans. Production during the first six months of 2007 has been
less than anticipated at the time of preparing the Company's December 31, 2006
reserve evaluation due to a number of factors, including a number of wells being
shut in for approximately 22 days during the quarter due to a third party
compressor failure and scheduled plant maintenance. The Company believes it is
prudent at this time to obtain an update of its reserve evaluation in light
these facts.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following management discussion and analysis ("MD&A") of financial
conditions and results of operations is as of August 29, 2007 and should be read
in conjunction with the unaudited financial statements and notes of Sierra Vista
Energy Ltd. ("Sierra Vista" or the "Company") for the three and six months ended
June 30, 2007 and the audited financial statements and notes for the year ended
December 31, 2006 and also should be read in conjunction with the Company's
December 31, 2006 MD&A. Additional information relating to the Company,
including the Company's December 31, 2006 Annual information Form, can be found
on the SEDAR website at www.sedar.com.
Discussion with regard to Sierra Vista's 2007 outlook is based on currently
available information. The financial data presented below has been prepared in
accordance with Canadian generally accepted accounting principles (GAAP). The
reporting and operating currency is the Canadian dollar.
This MD&A contains the terms funds flow from operations, funds flow per share
and operating netback which do not have standardized meanings prescribed by
Canadian GAAP and therefore may not be comparable to performance measures
presented by others. Funds flow from operations, as used by the Company, is
comprised of cash flow from operating activities before changes in non-cash
operating working capital. Operating netback represents revenue less royalties,
operating expenses and transportations expenses. These non-GAAP measures may not
be comparable to the calculation of similar measures for other entities. The
Company believes that operating netback and funds flow from (used by) operations
represent indicators of the Company's performance and a key measure of the
Company's ability to generate the necessary cash to fund future capital
expenditures. Funds from (used by) operations and operating netback as presented
is not intended to represent operating cash flow or operating profits for the
period nor should they be viewed as an alternative to cash flow from operating
activities, net earnings (loss) or other measures of financial performance
calculated in accordance with Canadian GAAP. See "Funds Flow from Operations"
and "Netbacks".
The term barrels of oil equivalent ("boe") may be misleading, particularly if
used in isolation. A boe conversion ratio of 6 thousand cubic feet (mcf) equals
1 barrel (bbl) is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency at the
wellhead. All boe conversions in this report are derived by converting gas to
oil in the ratio of six thousand cubic feet of gas to one barrel of oil.
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain information regarding the Company set forth in this report includes
forward looking statements. All statements other than statements of historical
facts contained in this MD&A, including statements regarding our future
financial position, business strategy and plans and objectives of management for
future operations, are forward-looking statements. The words "believe," "may,"
"will," "estimate," "continue," "anticipate," "intend," "should," "plan,"
"expect" and similar expressions, as they relate to us, are intended to identify
forward-looking statements. We have based these forward-looking statements
largely on our current expectations and projections about future events and
financial trends that we believe may affect our financial condition, results of
operations, business strategy and financial needs. These forward-looking
statements are subject to a number of risks, uncertainties and assumptions
described elsewhere in this report.
Other sections of this report may include additional factors, which could
adversely affect our business and financial performance. Moreover, we operate in
a very competitive and rapidly changing environment. New risk factors emerge
from time to time and it is not possible for our management to predict all risk
factors, nor can we assess the impact of all factors on our business or the
extent to which any factor, or combination of factors, may cause actual results
to differ materially from those contained in any forward-looking statements.
Readers are cautioned not to place undue reliance on forward-looking statements,
as there can be no assurance that the plans, intentions or expectations upon
which they are based will occur. By their nature, forward-looking statements
involve numerous assumptions, known and unknown risks and uncertainties, both
general and specific, that contribute to the possibility that the predictions,
forecasts, projections and other forward-looking statements will not occur,
which may cause the Company's actual performance and financial results in future
periods to differ materially from any estimates or projections of future
performance or results expressed or implied by such forward-looking statements.
We undertake no obligation to update publicly or revise any forward-looking
statements. Furthermore, the forward-looking statements contained in this report
are made as of the date of this report, and we undertake no obligation to update
publicly or to revise any of the included forward-looking statements unless
required by applicable securities laws, whether as a result of new information,
future events or otherwise. The forward-looking statements in this report are
expressly qualified by this cautionary statement.
CORPORATE OVERVIEW
Sierra Vista Energy Ltd. was incorporated under the laws of the Province of
Alberta on June 7, 2005 and commenced operation in September 2005. Sierra Vista
is a public junior oil and natural gas company focused on the exploration and
development and production of light crude oil and natural gas principally in the
Peace River Arch area of central Alberta. The Company's shares trade on the TSX
Venture exchange under the symbols SVR.A and SVR.B.
SELECTED INFORMATION
----------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Petroleum and natural
gas revenue, before
royalties $ 1,295,088 $ 655,831 $ 3,036,968 $ 1,330,327
Funds flow from
operations $ 22,806 $ 294,709 $ 717,879 $ 649,141
Funds flow from
operations per share
- basic $ 0.00 $ 0.02 $ 0.02 $ 0.04
Funds flow from
operations per share
- diluted $ 0.00 $ 0.02 $ 0.02 $ 0.03
Net (loss) income $ (780,683) $ 578,792 $ (1,120,583)$ 667,996
Net (loss) income per
share - basic $ (0.02) $ 0.03 $ (0.03)$ 0.04
Net (loss) income per
share - diluted $ (0.02) $ 0.03 $ (0.03)$ 0.03
Capital expenditures $ 667,561 $ 6,333,803 $ 5,081,612 $ 12,525,492
Working capital deficit,
including bank debt $(1,152,780) $(3,818,763)$ (1,152,780)$ (3,818,763)
Production (boe/d) 262 141 309 139
----------------------------------------------------------------------------
----------------------------------------------------------------------------
PRODUCTION
----------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Production
Crude oil and natural gas
liquids (bbl/d) 122 63 145 57
Natural gas (mcf/d) 839 466 985 491
----------------------------------------------------------------------------
Oil equivalent production
(boe/d) 262 141 309 139
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the three months ended June 30, 2007, Sierra Vista averaged 262 boe/d as
compared with 141 boe/d in the second quarter of 2006, an 86% increase quarter
over quarter. Production for the quarter was comprised of 122 boe/d of crude oil
and natural gas liquids and 839 mcf/d of natural gas resulting in a 47%
weighting to light (40oAPI), sweet, crude oil. Production during the quarter was
affected by the Company's Ante Creek wells being shut in for approximately 22
days during the quarter due to a third party compressor failure and scheduled
plant maintenance. As of the end of June, 2007, the Company's Ante Creek
property was back on production.
For the six months ended June 30, 2007, Sierra Vista averaged 309 boe/d as
compared to 139 boe/d for the first half of 2006, representing a 124% increase.
Production for the six months ended June 30, 2007 was comprised of 145 boe/d of
crude oil and natural gas liquids and 985 mcf/d of natural gas resulting in a
47% weighting to light, sweet, crude oil, consistent with the second quarter of
2007. The first half of 2007 production was also affected by the shut in of the
Company's Ante Creek wells during the second quarter as a result of the third
party compression and plant downtime.
PRICING
Benchmark Prices
----------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Crude oil - WTI (US$ per
Bbl) $ 64.94 $ 70.51 $ 61.53 $ 66.93
Crude oil - Edmonton Par
Price ($ per Bbl) $ 73.75 $ 80.59 $ 70.81 $ 74.76
Natural gas - AECO ($/mcf) $ 7.09 $ 5.98 $ 7.24 $ 6.72
Exchange rate ($US/$Cdn) 0.91 0.89 0.88 0.88
----------------------------------------------------------------------------
----------------------------------------------------------------------------
West Texas Intermediate at Cushing, Oklahoma ("WTI") is the benchmark reference
price for North American crude oil prices. Canadian crude oil prices are based
upon the average of several postings, primarily at Edmonton Alberta, and
represents the WTI price adjusted for quality and transportation differentials,
the US/CDN dollars exchange rate and local demand and supply influences. Crude
oil prices averaged US$64.94 per barrel and $73.75 at Edmonton for the second
quarter of 2007 as global political instability and concerns regarding crude oil
inventory levels continued to keep global oil prices unstable.
United States natural gas prices are commonly referenced to the New York
Mercantile Exchange at Henry Hub in Louisiana ("NYMEX") while Canadian natural
gas prices are typically referenced to the AECO Hub in Alberta. Natural gas
prices are influenced more by North American supply and demand than global
fundamentals. Natural gas prices averaged $7.09 per Mcf at AECO with prices
remaining very volatile as current natural gas inventory levels remain above the
five year average. North American weather over the remaining summer months and
into the winter heating season will be a major factor in future natural gas
pricing.
Realized Prices
----------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Average Prices
Crude oil and natural gas
liquids ($/bbl) $ 62.99 $ 66.30 $ 62.20 $ 64.77
Natural gas ($/mcf) $ 7.77 $ 6.54 $ 7.91 $ 7.43
----------------------------------------------------------------------------
Oil equivalent ($/boe) $ 54.26 $ 51.33 $ 54.35 $ 52.87
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Sierra Vista's averaged realized price for its crude oil and natural gas liquids
was $62.99 per barrel in the second quarter of 2007 and $7.77 per mcf for
natural gas. For the six months ended June 30, 2007, Sierra Vista's realized
price for crude oil and natural gas liquids was $62.20 per barrel and $7.91 per
mcf for natural gas. The Company continues to realize an approximately 10%
premium natural gas price as compared to the AECO benchmark prices, reflecting
the higher heat content of Sierra Vista's natural gas stream coming from the
Company's Ante Creek property. In addition, greater than 90% of Sierra Vista's
crude oil production is light, sweet oil (40 degrees API) which receives top
tier pricing relative to the Edmonton posted price.
REVENUES
----------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Production Revenue
Crude oil and natural gas
liquids $ 701,634 $ 378,859 $1,626,386 $ 669,652
Natural gas $ 593,373 $ 276,972 $1,410,582 $ 660,675
----------------------------------------------------------------------------
Total production revenue $1,295,007 $ 655,831 $3,036,968 $1,330,327
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the three months ended June 30, 2007, Sierra Vista recorded $701,634 in
crude oil and natural gas liquids sales and $593,373 in natural gas sales, an
85% and 114% increase, respectively over the second quarter of 2006. The
increase in crude oil revenue in the quarter was attributable to a 93% increase
in crude oil and natural gas liquids production in the second quarter of 2007
which is partially offset by a 5% reduction in the crude oil and natural gas
liquids prices in the quarter. The increase in natural gas revenue is a result
of an 80% increase in natural gas production in the second quarter of 2007
combined with a 19% increase in realized natural gas prices in the quarter, as
compared to the second quarter of 2006.
For the six months ended June 30, 2007, Sierra Vista recorded $1,626,386 in
crude oil and natural gas liquids sales and $1,410,582 in natural gas sales, an
85% and 114% increase respectively over the six months ended June 30, 2006. The
increase in crude oil revenue is a result of a 154% increase in crude oil and
natural gas liquids production for the six months ended June 30, 2007 which was
partially offset by a 4% reduction in the crude oil prices for 2007 as compared
to the same period in 2006. The increase in natural gas revenue is attributable
to a 101% increase in natural gas production and a 6% increase in natural gas
prices for the six months ended June 30, 2007 as compared to the same period in
2006.
The Company currently has no financial derivatives or physical delivery
contracts in place. All production volumes are currently sold into the Alberta
spot market.
ROYALTIES
----------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Gross royalties $ 248,832 $ 142,512 $ 556,121 $ 302,238
Alberta Royalty Tax
Credit - $ (35,751) - $ (75,082)
----------------------------------------------------------------------------
Net royalties $ 248,832 $ 106,761 $ 556,121 $ 227,156
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As a percentage of
revenue 19% 16% 18% 17%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
On a per boe basis $ 10.42 $ 8.35 $ 9.95 $ 9.03
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The average royalty rate for the second quarter 2007 increased to 19% of revenue
as compared to the average royalty rate in the second quarter of 2006 of 16%.
The increase in the average royalty rate is a result of the elimination of the
ARTC program by the Alberta government. Effective January 1, 2007, the Alberta
government eliminated the ARTC program which will have the affect of increasing
the royalties paid as a percentage of revenue. Royalties for the three and six
months ended June 30, 2007, on a per boe basis, were $10.42 and $9.95,
respectively, as compared to $8.35 and $9.03 for the same periods in 2006. The
increase on a per boe basis is a result of the elimination of the ARTC program.
OPERATING EXPENSES
----------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Operating expenses $ 425,953 $ 89,905 $ 759,092 $ 180,935
----------------------------------------------------------------------------
Operating expenses per
boe $ 17.85 $ 7.03 $ 13.59 $ 7.19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating expenses for the three months ended June 30, 2007 increased to $17.85
per boe, an increase from $7.03 per boe in the first quarter of 2006. The
increase in operating costs during the second quarter of 2007 is attributed to
the amount of time the Ante Creek wells were shut in during the second quarter
of 2007. In addition, operating cost adjustments relating to the first quarter
of 2007 increased the operating cost per boe in the quarter, while decreasing
such costs for the first quarter.
Operating expenses for the six months ended June 30, 2007 were $13.59 per boe
compared with $7.19 per boe in the six months ended June 30, 2006. As previously
indicated, the increase in operating costs for 2007 is attributable to the
Company's Ante Creek property being shut in for a period of time, due to a third
party compressor failure and scheduled plant maintenance.
Operating costs in the Company's Ante Creek property has averaged $10.75 per boe
over the past 12 month period ended June 30, 2007, without adjustment for the
downtime of the wells during the second quarter of 2007. This is of particular
importance to the Company as it illustrates the Company's Ante Creek property
operating costs are in line with the current industry operating cost levels. At
Kaybob, the Company has experienced higher operating costs due to the volume of
natural gas being processed by the Company's 100% owned compressor facility.
TRANSPORTATION EXPENSES
Transportation expenses were $35,798 or $1.50 per boe for the quarter ended June
30, 2007 as compared with $9,339 or $0.73 per boe for the second quarter of
2006. Transportation expenses were $60,196 or $1.08 per boe for the six months
ended June 30, 2007 as compared to $16,384 or $0.65 per boe in the six months
ended June 30, 2006.
NETBACKS
----------------------------------------------------------------------------
Three Months Ended Six Months Ended
Barrels of oil equivalent June 30 June 30
($/BOE) 2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue $ 54.26 $ 51.33 $ 54.35 $ 52.87
Royalties $ (10.42)$ (8.35)$ (9.95)$ (9.03)
Operating expenses $ (17.85)$ (7.03)$ (13.59)$ (7.19)
Transportation expenses $ (1.50)$ (0.73)$ (1.08)$ (0.65)
----------------------------------------------------------------------------
Field operating netback
($/BOE) $ 24.49 $ 35.22 $ 29.73 $ 36.00
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Field operating netbacks were $24.49 per boe for the quarter ended June 30, 2007
as compared with $35.22 per boe for the quarter ended June 30, 2006 and $29.73
per boe for the six months ended June 30, 2007 as compared to $36.00 per boe for
the six months ended June 30, 2006. The lower netbacks for both the quarter and
six months ended June 30, 2007 reflects the higher operating costs per boe
incurred as a result of the production downtime that occurred during these
periods.
GENERAL AND ADMINISTRATIVE EXPENSES
----------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Gross general and
administrative $ 443,692 $ 272,822 $ 892,959 $ 487,138
Overhead recoveries and
capitalized general
and administrative $ (115,129)$ (122,976)$ (277,354)$ (207,839)
----------------------------------------------------------------------------
Net general and
administrative
expenses $ 328,563 $ 149,846 $ 615,605 $ 279,299
----------------------------------------------------------------------------
----------------------------------------------------------------------------
During the second quarter 2007, general and administrative expenses ("G&A"), net
of recoveries, were $328,563 as compared to $149,846 for the quarter ended June
30, 2006. G&A, net of recoveries, for the six months ended June 30, 2007 was
$615,605 compared to $279,299 for the six months ended June 30, 2006. The
increase in net G&A is primarily due to increased staffing levels.
STOCK-BASED COMPENSATION
Stock-based compensation expense is the amortization over the vesting period of
the stock options granted to employees, directors, and key consultants of the
Company. The fair value of the stock options granted is estimated at the grant
date using the Black Scholes option pricing model. During the six months ended
June 30, 2007, the Company issued 982,500 stock options. Stock-based
compensation for the quarter ended June 30, 2007 was $220,033 as compared with
$12,394 for the quarter ended June 30, 2006. For the six months ended June 30,
2007, stock-based compensation was $395,866 as compared to the $17,297 for the
six months ended June 30, 2006. The increase in stock-based compensation expense
is a result of the increase in the numbers of options issued and the increased
volatility of the Company's stock price in 2007 as compared to the same periods
in 2006.
INTEREST EXPENSE
Bank debt interest expense for the quarter ended June 30, 2007 was $6,628
compared with $11,475 in the same quarter in 2006. The decrease in bank debt
interest expense for the quarter is due to the reduced level of bank debt
utilized during the quarter as a result of the equity and convertible debenture
financings closed in the first quarter of 2007. Bank debt interest expense for
the six months ended June 30, 2007 was $32,290 as compared to $11,475 for the
six months ended June 30, 2006.
Interest and accretion expense relating to the $10 million, 9.5% convertible
debenture for the quarter ended June 30, 2007 was $357,671 with no corresponding
expense in the second quarter of 2006. Interest expense for the second quarter
2007 relating to the convertible debenture was compiled of interest expense of
$236,850, accretion of the convertible debenture of $111,832 and amortization of
the debt portion of the convertible debenture issue costs of $8,989.
For the six months ended June 30, 2007, interest and accretion on the
convertible debenture was $501,967 with no corresponding expense for the six
months ended June 30, 2006. The interest and accretion expense is compiled of
interest expense of $333,151, accretion of the convertible debenture of $156,274
and amortization of the convertible debenture issue costs of $12,542.
The convertible debenture was issued on February 22, 2007. The accretion of the
convertible debenture liability component and amortization of the debenture
issue costs will be charged to interest expense using the effective interest
rate method.
DEPLETION, DEPRECIATION AND ACCRETION
----------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Depletion and
depreciation expense $ 740,506 $ 234,588 $ 1,722,295 $ 444,989
Accretion expense $ 7,458 $ 2,394 $ 14,916 $ 4,359
----------------------------------------------------------------------------
Total $ 747,964 $ 236,982 $ 1,737,211 $ 449,348
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Depletion, depreciation and accretion for the quarter ended June 30, 2007 was
$747,964 or $31.34 per boe as compared to $236,982 or $18.55 per boe for the
quarter ended June 30, 2006. Depletion, depreciation and accretion for the six
months ended June 30, 2007 was $1,737,211 or $31.09 per boe as compared with
$449,348 or $17.85 per boe for the six months ended June 30, 2006. The increase
in depletion, depreciation and accretion on an absolute and boe basis is a
result of increased production volumes and capital investment in the Company's
properties infrastructure, critical to the future development plans and the
earning of a prospective land base.
The Company follows the full cost method of accounting for its operations as
described in the CICA's accounting guideline 16, "Oil and Gas Accounting - Full
Cost". Accordingly, the cost of all wells, both successful and unsuccessful, are
added to the Company's capital base and are depleted on the unit of production
method based on estimated gross proved reserves at forecast prices and costs as
determined by independent engineers and the Company's internal estimates. Costs
of unproven properties, seismic and undeveloped land, net of impairments, are
excluded from the depletion calculation and future capital costs associated with
proved undeveloped reserves are included in the depletion calculation.
In recognizing an asset retirement obligation "ARO" associated with the
retirement of a tangible long-lived asset, the Company records a liability in
the period in which it is incurred and becomes determinable, with an offsetting
increase in the carrying amount of the associated asset. The cost of the
tangible asset, including the initially recognized ARO is depleted such that the
cost of the ARO is recognized over the useful life of the asset. The ARO is
recorded at fair value and accretion expense is recognized over time as the
discounted liability is accreted to its expected settlement value.
The provision for asset retirement obligations are determined by management in
consultation with the Company's independent engineers and are based on
prevailing regulations, costs, technology and industry standards. The Company
estimates that the total future value of its asset retirement obligations at
June 30, 2007 is $719,870. Current expenditures for actual abandonment and site
restoration in the quarter ended June 30, 2007 were nil.
TAXES
During the second quarter of 2007, the Company recorded a future income tax
recovery of $285,329 compared to a future income tax recovery in the same
quarter of 2006 of $533,459. For the six months ended June 30, 2007, the Company
recorded a future income tax recovery of $463,431 compared to a future income
tax recovery of $485,500 for the six months ended June 30, 2006. The Company
paid no cash taxes during the quarter and six month periods in 2007 and 2006.
As of June 30, 2007, the Company has approximately $25.5 million in tax pools
available to offset future taxable income.
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
----------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Net income (loss) $ (780,683) $ 578,792 $ (1,120,583) $ 667,996
Net income (loss) - per
basic share $ (0.02) $ 0.03 $ (0.03) $ 0.04
Net income (loss) - per
diluted share $ (0.02) $ 0.03 $ (0.03) $ 0.03
Weighted average shares
outstanding - basic(1) 41,676,950 18,486,298 39,916,242 18,424,088
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted average shares
outstanding - diluted(1) 41,676,950 19,189,117 39,916,242 19,144,401
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Assumes conversion of Class B shares as at June 30, 2007 at a price of
$1.00 per Class A share and as at June 30, 2006 at a price of $1.31 per
Class A share.
For the three and six months ended June 30, 2007 all outstanding stock options,
warrants and shares that would be issued upon the conversion of the convertible
debenture are anti-dilutive and have been excluded in calculating the diluted
weighted average shares outstanding.
At June 30, 2006, all outstanding stock options and warrants were in-the-money
and have been included in the weighted average diluted shares outstanding.
FUNDS FLOW FROM OPERATIONS
It is management's view that funds flow from operations is a useful measure of
performance and a good benchmark when comparing results from year to year or
quarter to quarter. Funds flow from operations is a non-GAAP measure, reconciled
with net loss in the table below:
----------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Net (loss) income $ (780,683) $ 578,792 $(1,120,583) $ 667,996
Add back (subtract)
items not effecting
cash:
Depletion, depreciation
and accretion $ 747,964 $ 236,982 $ 1,737,211 $ 449,348
Stock-based compensation $ 220,033 $ 12,394 $ 395,866 $ 17,297
Amortization of
convertible debenture
issue costs $ 8,989 - $ 12,542 -
Accretion of convertible
debenture $ 111,832 - $ 156,274 -
Future income tax
recovery $ (285,329) $ (533,459) $ (463,431) $ (485,500)
----------------------------------------------------------------------------
Funds flow from
operations $ 22,806 $ 294,709 $ 717,879 $ 649,141
Funds flow per share -
basic $ 0.00 $ 0.02 $ 0.02 $ 0.04
Funds flow per share -
diluted $ 0.00 $ 0.02 $ 0.02 $ 0.03
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SHARE CAPITAL
----------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Weighted Average Class A and
B shares outstanding
Basic - Class A 29,976,950 9,555,000 28,216,242 9,492,790
Basic - Class B(1) 11,700,000 8,931,298 11,700,000 8,931,298
----------------------------------------------------------------------------
Weighted average shares
outstanding - basic 41,676,950 18,486,298 39,916,242 18,424,088
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted average shares
outstanding - diluted 41,676,950 19,189,117 39,916,242 19,144,401
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Assumes conversion of Class B shares as at June 30, 2007 at a price of
$1.00 per Class A share and as at June 30, 2006 at a price of $1.31 per
Class A share.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Outstanding Securities Outstanding at
June 30
2007 2006
----------------------------------------------------------------------------
Class A shares 29,976,950 9,555,000
Class B shares 1,170,000 1,170,000
Stock options 2,912,500 912,500
Warrants 5,255,000 338,000
Convertible debenture 11,111,111 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As of the date of this MD&A, there were 29,976,950 Class A and 1,170,000 Class B
shares issued and outstanding.
For the three and six months ended June 30, 2007, all outstanding stock options,
warrants and convertible securities are anti-dilutive and have been excluded in
calculating the diluted shares outstanding.
The Company's Class B shares are convertible, at the option of the Company, at
any time after September 30, 2008 and before September 30, 2010, into Class A
shares. The number of Class A shares obtained upon conversion of each Class B
share will be equal to $10.00 divided by the greater of $1.00 and the then
current market price of the Class A shares. If conversion has not occurred by
the close of business September 30, 2010, then the Class B shares will be
convertible, at the option of the shareholder, at any time after October 1, 2010
and before November 1, 2010 into Class A shares on the same basis. On November
1, 2010, all remaining Class B shares will be automatically converted to Class A
shares on the same basis.
CAPITAL EXPENDITURES
----------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Land and seismic $ 194,215 $ 391,411 $ 592,074 $ 511,492
Drilling and completions $ 67,763 $ 3,612,391 $ 2,891,065 $ 8,257,352
Equipment and facilities $ 290,737 $ 155,663 $ 1,391,063 $ 1,519,599
Property acquisitions - $ 2,086,491 - $ 2,086,491
Other(1) $ 114,846 $ 87,847 $ 207,410 $ 150,558
----------------------------------------------------------------------------
Total $ 667,561 $ 6,333,803 $ 5,081,612 $ 12,525,492
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes capitalized general and administrative
DRILLING SUMMARY
----------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Gross Net Gross Net Gross Net Gross Net
----------------------------------------------------------------------------
Oil - - 1.0 1.0 1.0 0.7 2.0 2.0
Natural gas - - - - 1.0 0.2 2.0 1.5
Dry - - 1.0 0.4 - - 4.0 2.3
----------------------------------------------------------------------------
Total - - 2.0 1.4 2.0 0.9 8.0 5.8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
During the three months ended June 30, 2007, the Company did not participate in
the drilling of any wells. During the six months ended June 30, 2007, the
Company participated in the drilling of 2 gross (0.9 net) well with a 100%
success rate.
LIQUIDITY AND CAPITAL RESOURCES
At June 30, 2007, the Company had a $6,500,000 revolving bank credit facility.
The facility bears interest at prime plus 0.50% and is secured by a floating
first charge over all of the Company's assets. While the credit facility is
repayable on demand, the Company is not subject to scheduled repayments. As at
June 30, 2007, $683,561 was owing under the credit facility and of the date
hereof, $702,774 was owing under the credit facility. At June 30, 2007, the
Company was not in compliance with the net debt to trailing cash flow covenant
under the credit facility. The Company has received a waiver of the
non-compliance from the bank, conditional on the Company being in compliance
with all the covenants under the credit facility as of September 30, 2007. The
Company has until November 29, 2007 to determine and report whether it was in
compliance with these covenants.
As at June 30, 2007 and at the date hereof, the Company has a remaining
obligation to spend approximately $2,100,000 on qualified Canadian Exploration
Expenses before December 21, 2007, and an obligation to spend an additional
$5,000,400 on qualified Canadian Exploration Expenses before December 31, 2008.
The Company has total capital commitments of approximately $8,227,500 relating
to several farm-in and participation agreements signed with industry partners.
These farm-in commitments require capital expenditures of approximately
$7,300,000 over the next nine months, with the remaining capital expenditures to
be incurred when the Company's industry partner elects to drill the well
sometime in the future. Under one farm-in agreement in respect of the Ante Creek
area, the Company's obligations include spudding of one additional test well by
October 1, 2007, two additional test wells by December 31, 2007 and two
additional test wells by March 31, 2008, in each case to earn a 65% working
interest in the earned block containing the test well. The Company estimates
that the cost of each of these wells, to the production phase, is approximately
$1,460,000 per well. Certain of these expenditures in respect of these wells may
satisfy some of the Company's obligations in respect of the qualified Canadian
Exploration Expenses. The Company has already earned a 65% working interest in
3.25 sections in the Ante Creek area pursuant to this farm-in agreement. The
farm-in agreement provides that should the Company fail to meet any of the spud
date obligations or any other obligations thereunder, the farmor is entitled, on
notice to the Company, to terminate the agreement with respect to further
earnings, and in such event, 50% of any interest already earned by the Company
under the agreement shall be forfeited back to the farmor. As discussed below,
the Company plans to fund these capital requirements through internally
generated cash flow from operations, sale of property or farm-outs as
appropriate, bank and other forms of debt or further equity issues, where it is
deemed appropriate.
The Company's cash flow and earnings are highly sensitive to changes in
commodity prices, exchange rates and other factors that are beyond the control
of the Company.
CRITICAL ACCOUNTING ESTIMATES
Oil and Gas Reserve Estimates
Estimates of economically recoverable oil and natural gas reserves (including
natural gas liquids) and the future net cash flows therefrom are based upon a
number of variable factors and assumptions, such as commodity prices, projected
production from the properties, the assumed affects of regulation by government
agencies and future operating costs. All of these estimates may vary from actual
results. Estimates of the recoverable oil and natural gas reserves attributable
to any particular group of properties, classifications of such reserves based on
risk recovery and estimates of future net revenues expected therefrom, may vary.
The Company's actual production, revenues, taxes, development and operating
expenditures with respect to its reserves may vary from such estimates, and such
variances could be material.
Ceiling Test
The ceiling test calculation is used to assess the valuation of the Company's
petroleum and natural gas properties. The first part measures whether impairment
has occurred based on undiscounted future cash flows using estimated future
prices, costs and proved reserves. When the first part indicates impairment
exists, the second part of the test measures the amount of impairment based on
discounted estimated future cash flows from proved and probable reserves. The
Company reviews the related estimates when it performs its ceiling test on a
quarterly basis. The impact of changes in the estimates of future prices and
costs applied and the quantity of proved and probable reserves on the financial
statements could be material.
Unproven Properties
Costs related to unproven properties are excluded from costs subject to
depletion until proved reserves have been determined or their value is impaired.
These properties are reviewed quarterly, based on management's estimates of
future prospects and any impairment is transferred to the costs being depleted.
Stock-Based Compensation
The Company has a stock-based compensation plan which reserves shares of common
stock for issuance to key employees, consultants and directors. The Company
accounts for grants issued under this plan using the fair value recognition
provisions whereby the cost of options granted to employees is charged to income
with a corresponding increase in contributed surplus, based on an estimate of
the fair value determined using the Black-Scholes option pricing model and
amortized over the vesting period of the options issued.
Asset Retirement Obligations
The Company records the fair value of an asset retirement obligation as a
liability in the period in which it incurs a legal obligation associated with
the asset, normally when the asset is purchased or developed. The associated
asset retirement costs are capitalized as part of the carrying amount of the
long lived asset and depleted and depreciated using a unit-of-production method
over the life of the estimated proved reserves. Subsequent to the initial
measurement of the asset retirement obligations, the obligations are adjusted at
the end of each period to reflect the passage of time and changes in the
estimated future cash flows underlying the obligation.
Inherent in the fair value calculation of ARO are numerous assumptions and
judgments including the ultimate settlement amounts, inflation factors, credit
adjusted discount rates, timing of settlement, and changes in the legal,
regulatory, environmental and political environments. To the extent future
revisions to these assumptions impact the fair value of the existing ARO
liability, a corresponding adjustment is made to the petroleum and natural gas
properties balance.
BUSINESS RISKS
Exploration, development and production of petroleum and natural gas involves
many risks that even the combination of experience and diligent evaluation may
not be sufficient to overcome. Utilizing highly skilled professionals, focusing
in areas where the Company has existing knowledge and expertise or access to
such expertise, using the most up to date technology, and controlling costs to
maximize margins, mitigate these risks. The Company maintains a comprehensive
insurance program that insures liability and property consistent with good
industry practices. The program is designed to mitigate risks and protect
against significant loss. However, the Company is not fully insured against all
these risks, nor are all such risks insurable.
The reserve and recovery information contained in the Company's independent
reserve evaluation is only an estimate. The actual production and ultimate
recovery of reserves from the properties may be greater or less than the
estimates prepared by the independent reserve engineers. A significant portion
of the Company's assets are located at the Ante Creek property whose relatively
short production history may make estimates on this property more subject to
revisions. The reserve report was prepared using forecasted commodity prices as
determined by independent engineers. If lower prices for crude oil, natural gas
liquids and natural gas are realized by the Company, the present value of the
estimated future cash flows for the reserves would be reduced and such
reductions could be significant.
Financial risks include exposure to fluctuation in commodity prices, currency
exchange rates and interest rates. To mitigate the risks, the Company may enter
into physical contracts for the sale of crude oil, natural gas liquids and
natural gas at fixed prices. The Company may also institute financial hedging
techniques for interest rates, currency exchange rates and commodity prices. If
utilized, such transactions would be subject to certain limits on term and
amount as established by the Board of Directors.
Oil and Gas Risk
Inherent in development of oil and gas reserves are risks, among others, of
drilling dry holes, encountering production or drilling difficulties or
experiencing high decline rates in producing wells. In addition, a major market
risk exposure is in the pricing applicable to our oil and gas production.
Realized pricing is primarily driven by the prevailing worldwide price for crude
oil and spot prices applicable to our oil and natural gas production. Prices
received for oil and gas production have been and remain volatile and
unpredictable. If oil and gas prices decline significantly, even if only for a
short period of time, it is possible that non-cash write-downs of our oil and
gas properties could occur under the full-cost accounting method. Under these
rules, we review the carrying value of our proved oil and gas properties each
quarter to ensure that capitalized costs of proved oil and gas properties, net
of accumulated depreciation, depletion and amortization do not exceed the
"ceiling." This ceiling is the present value of estimated future net cash flows
from proved oil and gas reserves, discounted at 10 percent, plus the lower of
cost or fair value of unproved properties included in the costs being amortized,
net of related tax effects. If capitalized costs exceed this limit, the excess
is charged to additional depletion, depreciation and accretion expense. The
calculation of estimated future net cash flows is based on forecasted prices for
crude oil and natural gas except for volumes sold under long-term contracts.
Write-downs required by these rules do not impact cash flow from operating
activities; however, as discussed above, sustained low prices would have a
material adverse effect on future cash flows.
Financial and Liquidity Risks
The Company anticipates that it will make capital expenditures for the
acquisition, exploration, development and production of oil and natural gas in
the future. On an ongoing basis, the Company will typically plan to utilize
three sources of funding to finance its capital expenditure program; internally
generated cash flow from operations, debt where deemed appropriate and new
equity issues, if available at favourable terms.
Funds flow is influenced by many factors, which the Company cannot control, such
as commodity prices, the United States versus the Canadian exchange rate,
interest rates and changes to existing government regulations and tax policies.
Should circumstances affect cash flow in a detrimental way, the Company may have
limited ability to expand the capital necessary to undertake or complete future
drilling programs. In such circumstances, the Company would be required to
either reduce the level of its capital expenditures or supplement its capital
expenditure program with additional debt and/or equity financing. There can be
no assurance that debt or equity financing will be available or sufficient to
meet these requirements or, if debt or equity is available, that it will be on
terms acceptable to the Company. Moreover, future activities may require the
Company to alter its capitalization significantly. The inability of the Company
to access sufficient capital for its operations could have a material adverse
effect on the Company's financial condition, results of operations and
prospects.
Issuance of Debt
From time to time, the Company may enter into transactions to acquire assets or
the shares of other corporations. These transactions may be financed partially
or wholly with debt, which may increase the Company's debt levels above industry
standards. Neither the Company's articles nor its by-laws limit the amount of
indebtedness that the Company may incur. The level of the Company's indebtedness
from time to time could impair the Company's ability to obtain additional
financing in the future on a timely basis to take advantage of business
opportunities that my arise.
Supply of Service and Production Equipment
The supply of service and production equipment at competitive prices is critical
to the ability to add reserves at a competitive cost and produce these reserves
in an economic and timely fashion. In periods of increased activity, these
supplies and services can be difficult to obtain. Demand for such limited
equipment or access restrictions may affect the availability of such equipment
to the Company and may delay exploration and development activities. The Company
attempts to mitigate this risk by developing strong long-term relationships with
suppliers and contractors. There can be no assurances that these relationships
will increase the availability of the supplies and services.
Related Party Transactions
A director of the Company is also a partner in a law firm which is used
extensively for legal work related to the Company's activities. Fees for the
legal work are charged at the law firm's standard billing rates.
Contractual Obligations and Commitments
The Company has entered into a standard daywork contract with a drilling
contractor to utilize a drilling rig for a period of three years. The terms of
the contract call for a minimum requirement of 250 operating days per year for a
total of 750 operating days over the three-year term of the contract. The
contract expires in November 2009.
As a result of the Company issuing flow-through shares in 2006, the Company has
committed to spend $5,000,000 before December 31, 2007, on qualified Canadian
Exploration Expenses. The total estimated remaining obligation at June 30, 2007
under this commitment is approximately $2,100,000.
As a result of the Company issuing flow-through shares in February 2007, the
Company has committed to spend $5,000,400 before December 31, 2008, on qualified
Canadian Exploration Expenses.
The Company has entered into several farm-in and participation agreements to
explore for and develop petroleum and natural gas properties on lands of
industry partners. Total remaining capital commitments as of June 30, 2007
relating to these agreements is approximately $8,227,500. Certain expenditures
committed under the farm-in agreement will qualify for Canadian Exploration
Expenses.
The Company has entered into a five year office lease agreement commencing on
April 1, 2006. The following table outlines the Company's estimated remaining
lease commitments over the life of the agreement:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 2008 2009 2010 2011 Total
----------------------------------------------------------------------------
Lease payments $ 85,218 $ 173,800 $ 174,921 $ 178,284 $ 44,851 $ 657,074
----------------------------------------------------------------------------
----------------------------------------------------------------------------
GUARANTEES AND OFF-BALANCE SHEET ARRANGEMENTS
The Company has not entered into any off-balance sheet arrangements or
guarantees.
SUMMARY OF QUARTERLY RESULTS
The following table summarizes certain quarterly financial information
relating to the Company.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 2006
----------------------------------------------------
Q2 Q1 Q4 Q3
----------------------------------------------------------------------------
Production revenue
before royalties $ 1,295,088 $ 1,741,960 $ 1,082,723 $ 594,130
Funds flow from
operations (1) $ 22,806 $ 695,073 $ 152,382 $ 279,917
Funds flow per share -
basic (1) $ 0.00 $ 0.02 $ 0.01 $ 0.01
Funds flow per share -
diluted (1) $ 0.00 $ 0.02 $ 0.01 $ 0.01
Net loss $ (780,683) $ (339,900) $ (793,791) $ (105,355)
Net loss per share -
basic $ (0.02) $ (0.01) $ (0.03) $ 0.00
Net loss per share -
diluted $ (0.02) $ (0.01) $ (0.03) $ 0.00
Total assets $42,605,686 $47,488,192 $40,518,063 $27,433,823
Total bank debt $ 683,561 - $ 626,310 $ 500,000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2006 2005
----------------------------------------------------
Q2 Q1 Q4 Q3
----------------------------------------------------------------------------
Production revenue before
royalties $ 655,831 $ 674,496 $ 331,611 -
Funds flow from
operations (1) $ 294,709 $ 354,432 $ 179,576 $ (42,552)
Funds flow per share -
basic (1) $ 0.02 $ 0.02 $ 0.01 $ (0.03)
Funds flow per share -
diluted (1) $ 0.02 $ 0.02 $ 0.01 $ (0.03)
Net income (loss) $ 578,792 $ 89,204 $ (158,933) $ (103,592)
Net income (loss) per
share - basic $ 0.03 $ 0.01 $ (0.01) $ (0.08)
Net income (loss) per
share - diluted $ 0.03 $ 0.01 $ (0.01) $ (0.08)
Total assets $21,865,189 $17,386,000 $14,171,866 $ 2,491,859
Total bank debt $ 2,506,446 - - $ 750,000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Funds flow from operations and funds flow from operations per share are
non-GAAP measures. See "Funds Flow from Operations".
CHANGES IN ACCOUNTING POLICIES
Effective January 1, 2007, the Company adopted the Canadian Institute of
Chartered Accountants ("CICA") section 3855, "Financial Instruments -
Recognition and Measurement," section 3861, "Financial Instruments - Disclosure
and Presentation," and section 3865, "Hedges". These standards have been adopted
prospectively. For a discussion of the change in accounting policies, refer to
Note 3 of the unaudited interim financial statements for the three and six
months ended June 30, 2007.
DISCLOSURE CONTROLS AND PROCEDURES
Disclosure controls and procedures have been designed to ensure that information
required to be disclosed by the Company is accumulated and communicated to the
Company's management as appropriate to allow timely decisions regarding required
disclosure. The Company's Chief Executive Officer and Chief Financial Officer
have concluded, based on their evaluation, that the Company's disclosure
controls and procedures, as defined in Multilateral Instrument 52-109 -
Certification of Disclosure in Issuers' Annual and Interim Filings, are
effective to provide reasonable assurance that material information related to
the Company is made known to them, particularly during the interim period ended
June 30, 2007, and was recorded, processed, summarized and reported within the
time periods under applicable securities legislation.
INTERNAL CONTROLS OVER FINANCIAL REPORTING
There has been no changes in the Company's internal control over financial
reporting that occurred during the most recent interim period ended June 30,
2007 that may have materially affected, or are reasonably likely to materially
affect, the Company's internal control over financial reporting.
ADDITIONAL INFORMATION
Additional information relating to the Company is filed on the SEDAR website at
www.sedar.com. Also, information can also be obtained by contacting the Company
at Sierra Vista Energy Ltd., 850, 101 - 6th Avenue S.W., Calgary, Alberta, T2P
3P4 or by email at info@sierravista.ca. Information is also accessible on the
Company's website at www.sierravista.ca.
CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION
Some of the statements contained herein including, without limitation, financial
and business prospects, financial outlooks, and production forecasts may be
forward-looking statements which reflect management's expectations regarding
future plans and intentions, growth, results of operations, performance and
business prospects and opportunities. In particular, this news release contains
forward-looking statements pertaining to the quality of reserves, oil and
natural gas production levels, capital expenditure programs, projections of
market prices and costs, supply and demand for oil and natural gas; and
expectations regarding the Company's ability to raise capital and to continually
add to reserves through acquisitions and development.
The Company's actual results could differ materially from those anticipated in
these forward-looking statements as a result of the risk factors set forth above
and elsewhere in this news release including uncertainty of reserve estimates,
volatility in market prices for oil and natural gas, liabilities and risks
inherent in oil and natural gas operations, uncertainties associated with
estimating reserves, competition for, among other things, capital, acquisitions
or reserves, undeveloped lands and skilled personnel, geological, technical,
drilling and processing problems.
Words such as "may", "will", "should", "could", "anticipate", "believe",
"expect", "intend", "plan", "potential", continue" and similar expressions have
been used to identify these forward-looking statements. These statements reflect
management's current expectations and are based on uncertainties. Although the
forward-looking statements contained within this news release are based upon
what management believes to be reasonable assumptions, management cannot assure
that actual results will be consistent with these forward-looking statements.
Investors should not place undue reliance on forward-looking statements. These
forward-looking statements are made as of the date hereof and we assume no
obligation to update or revise them to reflect new events or circumstances
unless required under applicable securities laws.
Where amounts are expressed on a barrel of oil equivalent ("BOE") basis, natural
gas volumes have been converted to BOE using a ratio of 6,000 cubic feet of
natural gas to one barrel of oil equivalent. This conversion ratio is based upon
energy equivalent conversion method primarily applicable at the burner tip and
does not represent value equivalence at the wellhead. BOE figures may be
misleading, particularly if used in isolation.
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