Filed
Pursuant to Rule 424(b)(3)
Registration
No. 333-120659
PROSPECTUS
SUPPLEMENT NO. 3,
DATED
APRIL 2, 2008
(To
Prospectus dated July 31, 2007,
as
supplemented by Prospectus
Supplement
No. 1 dated November 21, 2007 and
Prospectus
Supplement No. 2 dated January 9, 2008)
WESTSIDE
ENERGY CORPORATION
3131
Turtle Creek Blvd, Suite 1300
Dallas,
TX 75219
(214)
522-8990
7,949,418
Shares of Common Stock
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This prospectus supplement supplements
the prospectus of Westside Energy Corporation (the “Company”) dated July 31,
2007 (the “Prospectus”), as supplemented by Prospectus Supplement No.
1 dated November 21, 2007 and Prospectus Supplement No. 2 dated January 9,
2008. You should read this prospectus supplement No. 3 in conjunction
with the Prospectus. This prospectus supplement must be delivered with the
Prospectus. This prospectus supplement includes the attached Annual
Report on Form 10-KSB for the fiscal year ended December 31, 2007 and filed with
the U.S. Securities and Exchange Commission on April 1, 2008.
The date
of this Prospectus Supplement is April 2, 2008.
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-KSB
x
ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15 (d)
OF THE
SECURITIES EXCHANGE ACT OF 1934
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For
the Fiscal Year Ended December 31, 2007
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Commission
File Number 0-49837
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WESTSIDE
ENERGY CORPORATION
(Name of
small business issuer in its charter)
Nevada
(State or
other jurisdiction of incorporation or organization)
88-0349241
(I.R.S.
Employer Identification No.)
3131
Turtle Creek Blvd, Suite 1300
Dallas,
TX 75219
214/522-8990
(Address,
including zip code, and
telephone
number, including area code, of
registrant's
principal executive offices)
Securities
registered pursuant to Section 12(b) of the Act:
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Title
of Each Class
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Name
of Each Exchange on which Registered
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Common
Stock, $0.01 par value
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American
Stock Exchange
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Check
whether the issuer is not required to file reports pursuant to Section 13 or
15(d) of the Exchange Act YES
o
NO
x
Check
whether the issuer (1) filed all reports required to be filed by Section 13 or
15(d) of the Exchange Act during the past 12 months (or for such shorter period
that the registrant was required to file such reports), and (2) has been subject
to such filing requirements for the past 90 days. YES
x
NO
o
Check if
there is no disclosure of delinquent filers in response to Item 405 of
Regulation S-B contained in this form, and no disclosure will be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-KSB or any
amendment to this Form 10-KSB.
o
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).
YES
o
NO
x
The
issuer's revenues for the fiscal year ended December 31, 2007 were
$6,440,087.
The
aggregate market value of the voting stock held by non-affiliates of the
registrant on December 31, 2007 was approximately $35,342,020, based on the
closing price of such stock on such date. The number of shares outstanding of
the registrant's Common Stock, par value $.01 per share, as of March 25, 2008
was 25,761,273.
Portions
of the registrant's definitive Proxy Statement for its 2008 annual meeting of
stockholders
(which
has not been filed as of the date of this filing) are incorporated by reference
into Part III.
Transitional Small Business
Disclosure format (Check
one):
YES
o
NO
x
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IN
DEX
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Page
Number
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PART
I.
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Items
1. & 2.
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2
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Item
3.
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21
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Item
4.
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21
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PART
II.
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Item
5.
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21
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Item
6.
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25
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Item
7.
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29
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Item
8.
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30
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Item
8A(T)
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30
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Item
8B.
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31
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PART
III.
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Item
9.
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31
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Item
10.
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31
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Item
11.
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31
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Item
12.
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31
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Item
13.
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32
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Item
14.
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35
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Forward-Looking
Statements
This
Annual Report on Form 10-KSB contains forward-looking statements within the
meaning of Section 24A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. These statements appear in a number of places
including “ITEMS 1 AND 2 DESCRIPTION OF BUSINESS AND PROPERTIES." These
statements regard:
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our belief that our portfolio of
large, predominantly undeveloped leasehold interests in the Barnett Shale
positions us for significant long-term growth in proved natural gas and
oil reserves and production;
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our belief that our remaining
undeveloped acreage in the Barnett Shale has substantial current
commercial potential, and our plan to exploit that potential through our
drilling program;
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our belief that our risk
assessments and due diligence reviews are consistent with industry
practices;
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our belief that we are
well-positioned to pursue selective acquisitions and attract industry
joint venture partners due to our asset base and technical
expertise;
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our beliefs regarding our key
competitive strengths;
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our belief that the current
royalty interests, liens and restrictions encumbering our properties do
not materially interfere with the use of our properties in the operation
of our business;
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our belief that we have
satisfactory title to or rights in all of our producing
properties;
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our belief that existing
regulation or any expected regulatory changes will not affect us in a way
that materially differs from the way it will affect our
competitors;
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our belief that access to oil and
natural gas pipeline services will generally be available to us to the
same extent as to our competitors
and
that we will not encounter difficulty in finding additional sales
opportunities, althrough we have entered into few sales contracts at this
time;
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our belief that we are in
substantial compliance with current applicable laws and regulations and
that continued compliance with existing requirements will not have a
material adverse impact on our
operations;
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our expectations regarding the
increase in our reserves, production and cash flow based on continued
drilling success within our acreage
position;
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our expectations as to the
sources of capital to finance our business and our ability to finance
ourselves through any period of time by means of such
sources;
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our plan to exploit our
properties’ potential through our drilling program, and to pursue further
acquisitions of natural gas and oil properties in the Barnett
Shale;
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our belief that we will reduce
unit costs by greater utilization of our existing infrastructure over a
larger number of wells;
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our belief regarding our ability
to sell all or most of our production in a manner consistent with industry
practices at prevailing rates by means of long-term sales contracts and
our ability to find additional sales
opportunities;
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our belief regarding compliance
with all applicable filing requirements of Section 16(a) of the Securities
Exchange Act of 1934;
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our belief regarding anticipated
improved performance of our Audit Committee that would result from a
greater number of members serving on such
committee;
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our belief
regarding the immaterialality of various miscellaneous costs incurred in
connection with a November 2007 private placement;
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our
belief regarding the reasonableness of our assumptions and estimates used
in connection with the preparation of our financial
statements;
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our
belief regarding the sufficiency of our available cash through the
anticipated time of the consummation of the merger with Crusader Energy
Group;
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our
expectations regarding the out of pocket expenses that we will incur in
connection with the business combination with Crusader Energy Group;
and
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our
plan to rectify the material weaknesses in our internal control over
financial reporting on consummation of a business combination with an
operating company that has the resources to perform the specialized oil
and gas accounting and implement the appropriate segregation of
duties.
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Such
statements can be identified by the use of forward-looking terminology such as
"believes," "expects," "may," "estimates," "will," "should," "plans" or
"anticipates" or the negative thereof or other variations thereon or comparable
terminology, or by discussions of strategy. Readers are cautioned that any such
forward-looking statements are not guarantees of future performance and involve
significant risks and uncertainties, and that actual results could differ
materially from those projected in the forward-looking statements. Factors that
could cause actual results to differ materially include, but are not limited to,
those discussed under "RISK FACTORS" hereinbelow. As a result, these
forward-looking statements represent our judgment as of the date of this Annual
Report. We do not express any intent or obligation to update these
forward-looking statements.
IT
EMS 1 and 2. DESCRIPTION OF BUSINESS AND
PROPERTIES.
OUR
COMPANY
We are an
independent natural gas and oil exploration and production company based in
Dallas, Texas with operations in the Barnett Shale in the Fort Worth Basin
located in north central Texas. We have been successful in identifying and
acquiring acreage positions where vertical and horizontal drilling, advanced
fracture stimulation and enhanced recovery technologies create the possibility
of economically developing and producing natural gas and oil reserves from the
Barnett Shale. We have assembled a portfolio of large, predominantly undeveloped
leasehold interests in the Barnett Shale, which we believe positions us for
significant long-term growth in proved natural gas and oil reserves and
production. As of December 31, 2007, we owned natural gas and oil leasehold
interests in approximately 82,071 gross (66,622 net)
acres. Approximately 94% of our gross acreage and 98% of our net
acreage are undeveloped. In addition, we own working interests in 73 gross (19.6
net) wells in the Barnett Shale.
As of
December 31, 2007, we had estimated net proved reserves of 17.4
Bcfe. We have identified approximately 500 drilling locations on our
existing acreage. Our estimated net proved reserves are located on approximately
5% of our net acreage. Based on our drilling results to date and third-party
results in adjacent areas, we believe that our remaining undeveloped acreage in
the Barnett Shale has substantial commercial potential, and we plan to exploit
that potential through our drilling program.
On
December 31, 2007, we entered into a Contribution Agreement (the “Contribution
Agreement”) pursuant to which we agreed to a merger with the privately held
Crusader Energy Group (“Crusader”). The merger is subject to our
stockholders’ approval. If the merger is approved and completed, the
ultimate equity owners of Crusader will receive approximately 157.4 million
shares of our common stock, subject (if additional cash capital contributions
are made to Crusader) to the issuance of additional shares up to approximately
14.3 million on the basis of one additional share for each three additional
dollars of capital contributed. After the completion of the merger,
we would have between 183.8 million and 198.1 million shares outstanding,
depending on the aggregate amount of any additional capital contributions to
Crusader and prior to the effectiveness of a planned one-for-two reverse stock
split of our common stock. Moreover, after the completion of the
merger, we will change our name to “Crusader Energy Group Inc.,” and our current
management will resign so that the Crusader management team can run the combined
company.
We were
incorporated under Nevada law in November 1995 as "Eventemp Corporation," a
company related to the automobile industry. Following several years of business
inactivity, we entered the natural gas and oil industry in February 2004 and in
the following month changed our name to "Westside Energy
Corporation."
Our
address is 3131 Turtle Creek Blvd., Suite 1300, Dallas, Texas 75219. Our
telephone number is (214) 522-8990 and our website address is
www.westsideenergy.com
.
Certain
terms used herein relating to the natural gas and oil industry are defined in
"Glossary of Certain Natural Gas and Oil Terms" included as Appendix A
hereto.
RISK
FACTORS
An
investment in shares of our common stock is highly speculative and involves a
high degree of risk. You should carefully consider all of the risks discussed
below, as well as the other information contained in this Annual Report. If any
of the following risks develop into actual events, our business, financial
condition or results of operations could be materially adversely affected and
the trading price of our common stock could decline.
Risks
Related to the Merger of Our Company and the Crusader Energy Group
We have
filed a preliminary proxy statement that describes a proposed merger of our
company with the Crusader Energy Group (referred to hereinafter as an aggregate
as “Crusader”). The proposed merger transaction creates certain risk
factors that should be considered along with the risk factors pertaining to the
combined company and our company standing alone. Risk factors
pertaining to our company standing alone are described in the subsection
captioned “
Risks Related to
Our Company and its Current Business”
below. Many, if not all,
of these risk factors will pertain to the combined company following any
consummation of the proposed merger transaction.
We
may not realize the benefits of integrating our companies.
To be
successful after the business combination, our company and the Crusader entities
will need to combine and integrate the operations of our separate companies into
one company. Integration will require substantial management
attention and could detract attention away from the day-to-day business of the
combined company. Our Company and the Crusader entities could
encounter difficulties in the integration process, such as the loss of key
employees or suppliers. If our company and the Crusader entities
cannot integrate our businesses successfully, our company and the Crusader
entities may fail to realize the benefits expected from the business
combination.
The
interests of our stockholders may not be represented in the Contribution
Agreement governing the proposed merger transaction (the “Contribution
Agreement”) because some directors and executive officers of ours have interests
in the transactions different from the interests of other
stockholders.
Some of
our directors and executive officers are parties to agreements or participate in
other arrangements that give them interests in the transactions contemplated by
the Contribution Agreement that are different from the interests of our
stockholders. These interests may have influenced these directors and
executive officers to recommend or support the business combination contemplated
by the Contribution Agreement. The receipt of compensation or other
benefits in connection with the business combination contemplated by the
Contribution Agreement, or the continuation of indemnification arrangements and
directors' and officers' insurance policies for current directors and executive
officers of ours following completion of the business combination, may influence
these directors and executive officers in making their votes and recommendations
related to the business combination contemplated by the Contribution
Agreement.
We
have borrowed money from one of the Crusader entities and one of the Crusader
entities purchased shares of common stock from us during 2007, which may have
created conflicts of interest in our determination to pursue the business
combination.
We began
discussing the business combination with representatives of the Crusader
entities in August 2007. On September 20, 2007 we entered into an
$8,000,000 credit facility with one of the Crusader entities, which loan has not
been repaid, and on November 9, 2007, one of the Crusader entities purchased
1,192,983 shares of our common stock for aggregate consideration of $3,400,000,
or $2.85 per share. We used the proceeds of the loan and stock
purchase to fund our operations. These transactions with the Crusader
entities may create conflicts of interest in our decision to pursue the business
combination.
If
the business combination contemplated by the Contribution Agreement does not
close, we will not benefit from the expenses we have incurred in the pursuit of
the business combination.
The
business combination contemplated by the Contribution Agreement may not be
completed. If the business combination is not completed, we will have
incurred substantial expenses for which no ultimate benefit will have been
received. We currently expect to incur out of pocket expenses
of $2.4 million for services in connection with the business
combination, consisting of investment banking, legal and accounting fees, and
financial printing and other related charges, much of which will be incurred
even if the business combination is not completed. In addition, if
the Contribution Agreement is terminated under specified circumstances, we will
be required to pay a $2 million termination fee and up to $500,000 of the
Crusader entities' expenses.
Because
the number of shares of our common stock to be issued to the owners of the
Crusader entities is fixed, the market value of our common stock that will be
issued to the owners of the Crusader entities will depend on the market price of
our common stock when the business combination contemplated by the Contribution
Agreement is completed.
The
owners of the Crusader entities will receive a fixed number of shares of our
common stock pursuant to the Contribution Agreement, rather than a number of
shares with a particular fixed market value. The market price of our
common stock when the business combination contemplated by the Contribution
Agreement occurs may vary significantly from its price on the date the
Contribution Agreement was executed, the date of this Annual Report or the date
on which our stockholders vote on the proposals at the annual
meeting.
The
number of shares of our common stock that we will issue to the owners of the
Crusader entities in the business combination will not be subject to reduction
in the event of any increase in the market price of our common stock that may
occur prior to completion of the business combination. Because the
number of shares of our common stock to be issued to the owners of the Crusader
entities will not be adjusted to reflect any changes in the market price of our
common stock, the market price of our common stock issued pursuant to the
Contribution Agreement may be higher or lower than the value of these shares on
earlier dates. At the time of the annual meeting, our stockholders
will not know the actual aggregate dollar value of the shares of our common
stock we will issue to the owners of the Crusader entities. Stock
price changes may result from a variety of factors that are beyond the control
of ours, including:
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changes
in our businesses, operations and
prospects;
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regulatory
considerations;
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market
assessments of the likelihood that the business combination will be
completed;
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the
timing of the completion of the business combination;
and
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general
market and economic conditions as well as market and economic conditions
related to the oil and gas
industry.
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We are
not permitted to terminate the Contribution Agreement or re-solicit the vote of
our stockholders solely because of changes in the market price of our common
stock.
The
issuance of shares of our common stock to the owners of the Crusader entities in
the business combination will result in immediate and substantial ownership
dilution to our current stockholders.
The
issuance of between 157.4 million and 171.7 million shares of our common
stock to the owners of the Crusader entities in the business combination will
significantly dilute the voting power and ownership percentage of our current
stockholders. Based on the number of shares of our common stock
outstanding as of March 31, 2008, the shares of our common stock to be issued in
the business combination would constitute between 85% and 87% of the outstanding
shares of our common stock immediately following completion of the business
combination and our current stockholders would own the remaining 13% to
15%.
The
interests of the owners of the Crusader entities may not be aligned with the
interests of our current stockholders.
Upon the
consummation of this offering, the Crusader entities will own between 85% and
87% of our outstanding common stock. The owners of the Crusader
entities will have control over all matters requiring stockholder approval,
including the election of our board of directors, the selection of our
management team, the determination of our corporate and management policies and
certain other decisions relating to fundamental corporate
actions. The interests of the owners of the Crusader entities may not
be aligned with the interests of the holders of our common stock.
Our
stockholders may experience dilution of their ownership interests due to the
future issuance of additional shares of our common stock.
We may in
the future issue our authorized and un-issued securities, resulting in the
dilution of the ownership interests of our stockholders. If the
business combination is consummated we will be authorized to issue 500 million
shares of common stock, up to 198,129,957 of which will be outstanding, and 10
million shares of preferred stock with preferences and rights as determined by
our board of directors. The potential issuance of additional shares
of common stock may create downward pressure on the trading price of our common
stock. We may also issue additional shares of our common stock or
other securities that are convertible into or exercisable for common stock in
connection with the hiring of personnel, future acquisitions, future public
offerings or private placements of our securities for capital raising purposes,
or for other business purposes. Any of these events may dilute our
stockholders’ ownership interest in us and have an adverse impact on the price
of our common stock.
In
addition, sales of a substantial amount of our common stock in the public
market, or the perception that these sales may occur, could reduce the market
price of our common stock. This could also impair our ability to
raise additional capital through the sale of our securities.
Risks
Related to Our Company and its Current Business
We are an early-stage company with
limited proved reserves and may not become profitable.
We are an
early-stage company, having entered the natural gas and oil industry in February
2004. Although we have acquired leases and undertaken exploratory and other
activities on the properties covered by our leases, nearly all of our properties
are undeveloped acreage. While we have had exploration success, to date we have
established a limited volume of proved reserves on our properties. We have
incurred net losses to date and do not expect to generate profits in the short
term. To become profitable, we would need to be successful in our acquisition,
exploration, development and production activities, all of which are
subject
to many risks beyond our control. Unless we sell sufficient volumes of natural
gas and oil to cover our expenses, we will not become profitable. Even if we
become profitable, we cannot assure you that our profitability will be
sustainable or increase on a periodic basis.
Our
credit facilities, one of which is secured by a large part of our assets,
features limiting operating covenants and requires substantial future payments,
expose us to certain risks and may adversely affect our ability to operate our
business.
Our
current, primary credit facility is provided by four private investment funds
managed by Wellington Management, LLC, which is the largest beneficial holder of
our outstanding common stock.
This credit
facility:
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initially
provided $25 million in funds, which were advanced in their entirety upon
completion of the credit facility, $12 million of which was used to retire
the outstanding balance owing on our then outstanding credit
facility;
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is
secured by a first lien on all of the oil and gas properties comprising
our Southeast and Southwest
Programs;
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grants to the lenders the right
to receive a lien in any and all of the proceeds received upon the sale of
a property comprising our North Program or any subsequent property
acquired with such proceeds;
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bears annual interest at 10.0%,
or (in the case of default) 12.0%
annually;
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grants to the lenders a three
percent (3.0%) overriding royalty interest (proportionately reduced to our
working interest) in all oil and gas produced from the properties now
comprising our Southeast and Southwest
Programs;
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contains limiting operating
covenants;
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contains events of default
arising from failure to timely repay principal and interest or comply with
certain covenants; and
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requires the repayment of the
outstanding balance of the loan in March
2009.
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Moreover,
on September 20, 2007, we entered into an additional, unsecured $8.0 million
credit facility with Knight Energy Group II, LLC (“Knight”), as
lender. Knight is an entity affiliated with Crusader Energy Group
with which Westside has entered into a Contribution Agreement more fully
described in “2007 Significant Events” below. Knight will
hereinafter be more fully described as “a Crusader entity”. This
credit facility:
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initially
provided $2.6 million in funds, $2.0 million of which were used to fund
the cash portion of the purchase price for an
acquisition;
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requires
a detailed Authority for Expenditure (an "AFE") as a condition to a draw
against the facility;
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bears
interest at an annual rate equal to the one-month London Interbank Offer
Rate (LIBOR) plus 5.0%;
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limits
the use of the proceeds from the facility for certain
purposes;
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contains
limiting operating covenants;
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contains
events of default arising from failure to timely repay principal and
interest or comply with certain covenants;
and
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requires
the repayment of the outstanding balance of the loan in March
2009.
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If we are
unable to generate sufficient cash flow from operations, we may have difficulty
in paying the outstanding balances of these loans in March 2009 when they
becomes due. If we were unable to pay these balances at that time, we
would be forced to seek an extension to the loans, or alternative debt or equity
financing. If we were unable to obtain such an extension or
alternative financing, we could default on the loans. If we default
on payment or other performance obligations under the loans, the lenders could
foreclose on a large part of our assets and exercise other creditor rights,
which could result in loss of all or nearly all of the value of our outstanding
equity. We may also be required to obtain the lenders’ consent to
certain events, such as sales of our assets, and any additional financing, which
if secured by our assets would likely need to be junior to our senior lenders’
lien.
Natural
gas and oil reserves decline once a property becomes productive, and we may need
to find new reserves to sustain revenue growth.
Even if
we add natural gas and oil reserves through our exploration activities, our
reserves will decline as they are produced. We will be constantly challenged to
add new reserves through further exploration or further development of our
existing properties. There can be no assurance that our exploration and
development activities will be successful in adding new reserves. If we fail to
replace reserves, our level of production and cash flows will be adversely
impacted.
Our
focus on exploration activities exposes us to greater risks than are generally
encountered in later-stage natural gas
and
oil property development businesses.
Much of
our current activity involves drilling exploratory test wells on properties with
no proved natural gas and oil reserves. While all drilling (whether
developmental or exploratory) involves risks, exploratory drilling involves
greater risks of dry holes or failure to find commercial quantities of natural
gas and oil. The economic success of any project will depend on numerous
factors, including the ability to estimate the volumes of recoverable reserves
relating to the project, rates of future production, future commodity prices,
investment and operating costs and possible environmental liabilities. All of
these factors may impact whether a project will generate cash flows sufficient
to provide a suitable return on investment. If we experience a series of failed
drilling projects, our business, results of operations and financial condition
could be materially adversely affected.
We
depend on our current management team, the loss of any member of which could
delay the further implementation of our business plan or cause business failure.
We do not carry key man life insurance and have not required non-competition
agreements.
We depend
on the services of management to meet our business development objectives. As an
early-stage company, we would expect to encounter difficulty replacing any of
them. The loss of any person on our management team could materially adversely
affect our business and operations. We do not carry key person life insurance
for any member of our management team. We have not required that any employee
enter into a non-competition agreement.
We
may rely on independent experts and technical or operational service providers
over whom we may have limited control.
We use
independent contractors to assist us in identifying desirable natural gas and
oil prospects to acquire and provide us with technical assistance and services.
We also may rely upon the services of geologists, geophysicists, chemists,
landmen, title attorneys, engineers and scientists to explore and analyze our
prospects to determine a method in which the prospects may be developed in a
cost-effective manner. In addition, we intend to rely on the owners and
operators of oil rigs and drilling equipment, and on providers of oilfield
services, to drill and develop our prospects to production. Moreover, if our
properties hold commercial quantities of natural gas and oil, we would need to
rely on third-party gathering or pipeline facilities to transport and purchase
our production. Our limited control over the activities and business practices
of these providers, any inability on our part to maintain satisfactory
commercial relationships with them or their failure to provide quality services
could materially and adversely affect our business, results of operations and
financial condition.
We
do not always undertake a full title review of, or obtain title insurance on,
our properties.
Consistent
with industry practice, rather than incur the expense of formal title
examination on a natural gas or oil property to be placed under lease, we have
relied on and plan to continue to rely on the judgment of natural gas and oil
lease brokers or landmen who perform the field work in examining government
records before placing a mineral interest under lease. Although an operator of a
well customarily obtains a preliminary title review to avoid obvious title
deficiencies prior to the drilling of a natural gas or oil well, we do not
always engage counsel to examine title until just prior to drilling the well.
This could result in our having to cure title defects that could affect
marketability, which would increase costs. We may conclude from a title
examination that a lease was purchased from someone other than the owner, in
which case the lease would be worthless to us and prevent us from recovering our
expenditures.
Our
review of properties cannot assure that all deficiencies or environmental risks
may be identified or avoided.
Although
we undertake reviews that we believe are consistent with industry practice for
our projects, these reviews are often limited in scope and may not reveal all
existing or potential problems, or permit us to become sufficiently familiar
with the related properties to assess their deficiencies and capabilities.
Moreover, we do not perform an inspection on every well, and our inspections may
not reveal all structural or environmental problems. Even if our inspections
identify problems, the seller or lessor may be unwilling or unable to provide
effective contractual protection. We generally do not receive indemnification
for environmental liabilities and, accordingly, may have to pursue many projects
on an "as is" basis, which could require us to make substantial expenditures to
remediate environmental contamination on acquired properties. If a property
deficiency or environmental problem cannot be satisfactorily remedied to warrant
commencing drilling operations on a property, we could lose our entire
investment in the property.
Our
properties may be subject to substantial impairment of their recorded
value.
The
accounting rules for our properties that have proven reserves require us to
review periodically their carrying value for possible impairment. If natural gas
and oil prices decrease or if the recoverable reserves on a property are revised
downward, we may be required to record impairment write-downs, which would
result in a negative impact to our financial position. We also may be required
to record impairment write-downs for properties lacking economic access to
markets and must record impairment write-downs for leases as they expire, both
of which could also negatively impact our financial position. We
recorded $4.3 million of impairment charges in 2006. In 2007,
we recorded $4.5 million of impairment charges.. Please see the
discussion of the 2007 impairment in the results of operation section of
Management’s discussion and analysis.
Our
acquisition of two related natural gas and oil companies could expose us to
undisclosed liabilities.
In March
2006, we expanded our base of natural gas and oil producing properties through
an acquisition of EBS Oil and Gas Partners Production Company, L.P. and an
affiliated operations company that were engaged in the drilling and completion
of natural gas and oil wells in Texas. Although we have largely integrated their
activities into ours and assessed the quality of their properties, we may
encounter risks, and possibly incur remediation costs, from existing or
potential problems and liabilities that were not disclosed to us, or were
unknown to the acquired companies, when the transaction was
completed.
We
have not insured and cannot fully insure against all risks related to our
operations, which could result in substantial claims for which we are
underinsured or uninsured.
We have
not insured and cannot fully insure against all risks and have not attempted to
insure fully against risks where coverage is prohibitively expensive. Losses and
liabilities arising from uninsured and underinsured events, which could arise
from even one catastrophic accident, could materially and adversely affect our
business, results of operations and financial condition. We do not carry
business interruption insurance coverage. Our exploration, drilling and other
activities are subject to risks such as:
|
|
*
|
environmental hazards, such as
uncontrollable flows of natural gas, oil, brine, well fluids, toxic gas or
other pollution into the environment, including groundwater
contamination;
|
|
|
*
|
abnormally pressured
formations;
|
|
|
*
|
mechanical failures of drilling
equipment;
|
|
|
*
|
personal injuries and death,
including insufficient worker compensation coverage for third-party
contractors who provide drilling services;
and
|
|
|
*
|
natural disasters, such as
adverse weather conditions.
|
We
have hedged and intend to continue hedging a portion of our production, which
may result in our making cash payments or prevent us from receiving the full
benefit of increases in prices for oil and gas.
We reduce
our exposure to the volatility of oil and gas prices by actively hedging a
portion of our production. Hedging also prevents us from receiving the full
advantage of increases in oil or gas prices above the fixed amount specified in
the hedge agreement. In a typical hedge transaction, we have the right to
receive from the hedge counterparty the excess of the fixed price specified in
the hedge agreement over a floating price based on a market index, multiplied by
the quantity hedged. If the floating price exceeds the fixed price, we must pay
the counterparty this difference multiplied by the quantity hedged even if we
had insufficient production to cover the quantities specified in the hedge
agreement. Accordingly, if we have less production than we have hedged when the
floating price exceeds the fixed price, we must make payments against which
there are no offsetting sales of production. If these payments become too large,
the remainder of our business may be adversely affected. In addition, our
hedging agreements expose us to the risk of financial loss if the counterparty
to a hedging contract defaults on its contract obligations. In the
first quarter of 2008, we significantly increased our volume of hedging beyond
that which we have historically undertaken. We are not now in a
position to know the extent of the ultimate benefits or additional costs to us
resulting from this elevated level of hedging.
Operational
impediments may hinder our access to natural gas and oil markets or delay our
production.
The
marketability of our production depends in part upon the availability, proximity
and capacity of pipelines, natural gas gathering systems and processing
facilities. For example, there are no existing pipelines in certain areas where
we have acreage. Therefore, if drilling results are positive in these areas, new
gathering systems would need to be built to deliver any natural gas and oil to
markets. There can be no assurance that we would have sufficient liquidity to
build such a system or that third parties would build a system that would allow
for the economic development of any such production.
We
deliver natural gas and oil through gathering systems and pipelines that we do
not own. These facilities may not be available to us in the future. Our ability
to produce and market natural gas and oil is affected and also may be harmed
by:
|
|
*
|
the lack of pipeline transmission
facilities or carrying
capacity;
|
|
|
*
|
federal and state regulation of
natural gas and oil production;
and
|
|
|
*
|
federal and state transportation,
tax and energy policies.
|
Any
significant change in our arrangements with gathering system or pipeline owners
and operators or other market factors affecting the overall infrastructure
facilities servicing our properties could adversely impact our ability to
deliver the natural gas and oil we produce to markets in an efficient manner. In
some cases, we may be required to shut in wells, at least temporarily, for lack
of a market because of the inadequacy or unavailability of transportation
facilities. If that were to occur, we would be unable to realize revenue from
those wells until arrangements were made to deliver our production to
market.
We
have limited control over activities on properties we do not operate, which
could reduce our production and revenues.
A
substantial portion of our business activities is conducted through joint
operating agreements under which we own partial interests in natural gas and oil
properties. We do not operate all of the properties in which we have an interest
and in some cases we do not have the ability to remove the operator in the event
of poor performance. As a result, we may have a limited ability to exercise
influence over normal operating procedures, expenditures or future development
of underlying properties and their associated costs. The failure of an operator
of our wells to adequately perform operations, or an operator's breach of the
applicable agreements, could reduce our production and revenues. The success and
timing of our drilling and development activities on properties operated by
others therefore depend upon a number of factors outside of our and the
operator's control, including:
|
|
*
|
timing and amount of capital
expenditures;
|
|
|
*
|
expertise and financial
resources; and
|
|
|
*
|
inclusion of other
participants.
|
Unless
we generate sufficient revenue, we will require additional capital, which may
not be available on favorable terms or at all.
If our
cash flows from operations are insufficient to fund our expected capital needs,
or our needs are greater than anticipated, we will need to raise additional
capital through private or public sales of equity securities or the incurrence
of additional indebtedness. Additional funding may not be available on favorable
terms or at all. We may be required to raise additional capital to fund our
operations for the foreseeable future. If we require but cannot secure outside
financing, we could be forced to dispose of certain of our assets or curtail our
operations substantially or cease business altogether, which could result in a
substantial reduction or elimination of the value of our then-outstanding
equity. If we raise additional funds through public or private sales of equity
securities, the sales may be at prices below the market price of our stock, and
our stockholders may suffer significant dilution.
Our
competitors include larger, better-financed and more experienced
companies.
The
natural gas and oil industry is intensely competitive and, as an early-stage
company, we must compete against larger companies that may have greater
financial and technical resources than we have and substantially more experience
in our industry. These competitive advantages may better enable our competitors
to sustain the impact of higher exploration and production costs, natural gas
and oil price volatility, productivity variances among properties, overall
industry cycles and other factors related to our industry. Their advantage may
also negatively impact our ability to acquire prospective properties, develop
reserves, attract and retain quality personnel and raise capital.
Risks
Related to the Natural Gas and Oil Business
Natural
gas and oil are commodities subject to price volatility based on many factors
outside the control of producers, and low prices may make properties uneconomic
for future production.
Natural
gas and oil are commodities, and, therefore, their prices are subject to wide
fluctuations in response to relatively minor changes in supply and demand.
Historically, the markets for natural gas and oil have been volatile. These
markets will likely continue to be volatile in the future. The prices a
producer may expect and its level of production depend on numerous factors
beyond its control, such as:
|
|
*
|
changes in global supply and
demand for natural gas and
oil;
|
|
|
*
|
the actions of the Organization
of Petroleum Exporting Countries, or
OPEC;
|
|
|
*
|
the price and quantity of imports
of foreign natural gas and
oil;
|
|
|
*
|
political conditions, including
embargoes, in natural gas and oil producing
regions;
|
|
|
*
|
the level of global natural gas
and oil inventories;
|
|
|
*
|
technological advances affecting
energy consumption; and
|
|
|
*
|
the price and availability of
alternative fuels.
|
Lower
natural gas and oil prices may not only decrease revenues on a per unit basis,
but also may reduce the amount of natural gas and oil that can be economically
produced. Lower prices will also negatively impact the value of proved
reserves.
Natural
gas and oil exploration and production present many risks that are difficult to
manage.
Our
natural gas and oil exploration, development and production activities are
subject to many risks that may be unpredictable and are difficult to manage. In
addition, the cost and timing of drilling, completing and operating wells is
often uncertain. In conducting exploration and development activities, the
presence of unanticipated pressure or irregularities in formations,
miscalculations or accidents may cause exploration, development and production
activities to be unsuccessful. This could result in a total loss of our
investment in a particular property. If exploration efforts are unsuccessful in
establishing proved reserves and exploration activities cease, the amounts
accumulated as unproved costs will be charged against earnings as
impairments.
Shortages
of rigs, equipment, supplies and personnel could delay or otherwise adversely
affect our cost of operations or our ability to operate according to our
business plan.
If
domestic drilling activity increases, particularly in fields where we operate, a
general shortage of drilling and completion rigs, field equipment and qualified
personnel could develop. As a result, the costs and delivery times of rigs,
equipment and personnel could be substantially greater than in previous years.
From time to time, these costs have sharply increased and could do so again. The
demand for and wage rates of qualified drilling rig crews generally rise in
response to the increasing number of active rigs in service and could increase
sharply in the event of a shortage. Shortages of drilling and completion rigs,
field equipment or qualified personnel could delay, restrict or curtail our
exploration and development operations, which could in turn adversely affect our
results of operations.
Conducting
operations in the natural gas and oil industry subjects us to complex laws and
regulations, including environmental regulations, that can have a material
adverse effect on the cost, manner or feasibility of doing
business.
Companies
that explore for and develop, produce and sell natural gas and oil in the United
States are subject to extensive federal, state and local laws and regulations,
including complex tax laws and environmental laws and regulations, and are
required to obtain various permits and approvals from federal, state and local
agencies. If these permits are not issued or unfavorable restrictions or
conditions are imposed on our drilling activities, we may not be able to conduct
our operations as planned. Alternatively, failure to comply with these laws and
regulations, including the requirements to obtain any permits, may result in the
suspension or termination of our operations and subject us to administrative,
civil and criminal penalties. Compliance costs can be significant. Further,
these laws and regulations could change in ways that substantially increase our
costs and associated liabilities. We cannot be certain that existing laws or
regulations, as currently interpreted or reinterpreted in the future, or future
laws or regulations will not harm our business, results of operations and
financial condition. For example, matters subject to regulation and the types of
permits required include:
|
|
*
|
water discharge and disposal
permits for drilling
operations;
|
|
|
*
|
occupational safety and
health;
|
|
|
*
|
air quality, noise levels and
related permits;
|
|
|
*
|
rights-of-way and
easements;
|
|
|
*
|
calculation
and payment of royalties;
|
|
|
*
|
gathering, transportation and
marketing of natural gas and
oil;
|
Under
these laws and regulations, we could be liable for:
|
|
*
|
discharge of hazardous
materials;
|
|
|
*
|
remediation and clean-up
costs;
|
|
|
*
|
fines and penalties;
and
|
|
|
*
|
natural resource
damages.
|
Risks
Related to Our Common Stock
Our
management team members beneficially own a significant percentage of our common
stock and can substantially influence corporate actions.
As of
March 31 2008, our directors and executive officers own about 13.5% of our
outstanding common stock. Their ownership would increase if they exercise the
outstanding warrants they own or are issued incentive shares that we must issue
if certain performance benchmarks are reached. As a result, our directors and
executive officers are able to substantially influence all matters requiring
stockholder approval, including the election of directors and approval of
significant corporate transactions, such as a re-capitalization or other
fundamental corporate action. This concentration of ownership may have the
effect of facilitating, delaying or preventing a change in control, which may be
to the benefit of our directors and executive officers but not in the best
interests of our other stockholders. The concentration of ownership could also
significantly reduce the capacity of our stockholders to change the Board of
Directors if stockholders are dissatisfied or disagree with the Board's
oversight of management’s determination of business policy, or the business
decisions of officers who are appointed by the Board. This lack of stockholder
control could cause investors to lose all or part of their investment in
us.
Provisions
in our articles of incorporation, our bylaws and Nevada law may make it more
difficult to effect a change in control, which could adversely affect the price
of our common stock.
Provisions
of our articles of incorporation, our bylaws and Nevada law could make it more
difficult for a third party to acquire us, even if doing so would be beneficial
to our stockholders. We may issue shares of preferred stock in the future
without stockholder approval and upon such terms as our Board of Directors may
determine. Our issuance of preferred stock could have the effect of making it
more difficult for a third party to acquire, or of discouraging a third party
from acquiring, a majority of our outstanding stock and potentially prevent the
payment of a premium to our stockholders in an acquisition.
Our
articles of incorporation and bylaws contain provisions that could delay, defer
or prevent a change in control of us or our management. These provisions
include:
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|
*
|
providing that special meetings
of stockholders may only be called by the Board pursuant to a resolution
adopted by:
|
|
|
(iii)
|
a majority of the members of the
Board;
|
|
|
*
|
prohibiting cumulative voting in
the election of directors.
|
These
provisions also could discourage proxy contests and make it more difficult for
you and our other stockholders to elect directors and take other corporate
actions. As a result, these provisions could make it more difficult for a third
party to acquire us, even if doing so would benefit our stockholders, and may
limit the price that potential investors are willing to pay in the future for
shares of our common stock.
We are
also subject to provisions of the Nevada corporation law that prohibit business
combinations with persons owning 10% or more of the voting shares of a
corporation's outstanding stock, unless the combination is approved by the Board
of Directors prior to the person owning 10% or more of the stock, for a period
of three years, after which the business combination would be subject to special
stockholder approval requirements. This provision could deprive our stockholders
of an opportunity to receive a premium for their common stock as part of a sale
of our company or may otherwise discourage a potential acquiror from attempting
to obtain control from us, which in turn could have a material adverse effect on
the market price of our common stock.
Trading
in our common stock may involve price and volume volatility.
Our
common stock has been trading on the American Stock Exchange since June 2005,
before which time our common stock was traded in the over-the-counter market on
the OTC Electronic Bulletin Board. The volume of trading in our common stock
varies greatly and may often be light, resulting in what is known as a
"thinly-traded" stock. Until a larger secondary market for our common stock
develops, the price of our common stock may fluctuate substantially. The price
of our common stock may also be impacted by any of the following, some of which
may have little or no relation to our company or industry:
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*
|
the breadth of our stockholder
base and the extent to which securities professionals follow our common
stock;
|
|
|
*
|
investor perception of us and the
natural gas and oil industry, including industry
trends;
|
|
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*
|
domestic and international
economic and capital market conditions, including fluctuations in
commodity prices;
|
|
|
*
|
responses to quarter-to-quarter
variations in our results of
operations;
|
|
|
*
|
announcements of significant
acquisitions, strategic alliances, joint ventures or capital commitments
by us or our competitors;
|
|
|
*
|
additions or departures of key
personnel;
|
|
|
*
|
sales or purchases of our common
stock by large stockholders or our
insiders;
|
|
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*
|
accounting pronouncements or
changes in accounting rules that affect our financial reporting;
and
|
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*
|
changes in legal and regulatory
compliance unrelated to our
performance.
|
We
have not paid cash dividends on our common stock and do not anticipate paying
any dividends on our common stock in the foreseeable future.
Under the
terms of our outstanding credit facility, we may not pay dividends on our common
stock. We anticipate that we will retain all future earnings and other cash
resources for the operation and development of our business. Accordingly, we do
not intend to declare or pay any cash dividends on our common stock in the
foreseeable future. Payment of future dividends, if any, will be at the
discretion of the Board of Directors after taking into account various factors,
including our financial condition, results of operations, current and
anticipated cash needs and plans for expansion.
BUSINESS
AND PROPERTIES
Overview
We are an
independent natural gas and oil exploration and production company based in
Dallas, Texas with operations in the Barnett Shale in the Fort Worth Basin
located in north central Texas. We have been successful in identifying and
acquiring acreage positions where vertical and horizontal drilling, advanced
fracture stimulation and enhanced recovery technologies create the possibility
of economically developing and producing natural gas and oil reserves from the
Barnett Shale. We have assembled a portfolio of large, predominantly undeveloped
leasehold interests in the Barnett Shale, which we believe positions us for
significant long-term growth in proved natural gas and oil reserves and
production. As of December 31, 2007, we owned natural gas and oil leasehold
interests in approximately 82,071 gross (66,622 net) acres, approximately 98% of
which are undeveloped. In addition, we own working interests in 73 gross (19.6
net) wells in the Barnett Shale. We were incorporated under Nevada law in
November 1995 as "Eventemp Corporation," a company with activities related to
the automotive industry. Following several years of business inactivity, we
entered the natural gas and oil industry in February 2004 and in the following
month changed our name to "Westside Energy Corporation."
The
Barnett Shale
The
Barnett Shale is one of the largest and most active domestic natural gas plays
in the United States. The Barnett Shale formation, which can reach a thickness
of up to approximately 1,000 feet, is located at depths of 6,500 to 9,000 feet
and covers an area that spans approximately 18 counties in north central Texas.
The shale formation is characterized by extremely low permeability requiring
hydraulic fracturing to enable economic recovery of natural gas and oil
reserves. Technological advances in fracturing techniques and horizontal
drilling have allowed natural gas production from the Barnett Shale to grow to
over 2.3 Bcf/d from more than 7,100 wells with an additional 4,350
permitted drilling locations according to the Texas Railroad
Commission.
Significant
Company Events in 2007
The
following is a brief description of our most significant events occurring in
2007:
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|
*
|
We
completed 17 gross wells (5.9 net
wells)..
|
|
|
*
|
We entered into a new $25 million
senior credit facility to replace our then existing credit
facility. The new senior credit facility was provided by four
private investment funds managed by Wellington Management Company, LLP,
then and now the largest beneficial holder of our outstanding common
stock. For more information about this senior credit facility,
see "ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS - Liquidity and Capital
Resources" below.
|
|
|
*
|
We
entered into an additional, unsecured $8 million revolving credit facility
with Knight Energy Group II (“Knight”), a Crusader entity, with a maturity
date of March 31, 2009. For more information about this
additional credit facility, see "ITEM 6. MANAGEMENT'S DISCUSSION AND
ANALYSIS - Liquidity and Capital Resources"
below.
|
|
|
*
|
We
consummated a Purchase and Sale Agreement with GulfTex Operating, Inc. and
TD Energy Services, Inc. whereby we purchased various working interests in
five producing wells and leasehold covering an aggregate of 1,400 gross
acres in Denton, Johnson, and Tarrant Counties, Texas, for $5,010,000,
comprising cash of $2 million and 904,000 of our common
shares. Proved reserves associated with this acquisition were
7.6 BCF of natural gas at December 31,
2007.
|
|
|
*
|
During
November 2007, we completed the private placement of an aggregate of
2,456,140 shares of our common stock, $.01 par value, at a price of $2.85
per share. The cash offering resulted in approximately $7.0 million in
gross proceeds. We incurred various miscellaneous costs
believed to be immaterial in connection with the consummation of this
placement. The shares were issued to a total of three investors
that included (a) two private investment funds managed by Wellington
Management, LLC (“Wellington”), and (b) Knight Energy Group II, LLC
("Knight"), a Crusader entity. Wellington had in the past been
the largest beneficial holder of our outstanding common stock, and (by the
acquisition by the two funds managed by Wellington of shares pursuant to
the Purchase Agreement) Wellington has once again become the largest
beneficial holder of our outstanding common stock. Moreover,
Knight recently provided an unsecured revolving credit facility in an
aggregate amount of up to $8
million.
|
|
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*
|
On
December 31, 2007, we entered into a Contribution Agreement (the
“Contribution Agreement”) pursuant to which we agreed to a merger with the
privately held Crusader Energy Group (“Crusader”). The merger
is subject to our stockholders’ approval. If the merger is
approved and completed, the ultimate equity owners of Crusader will
receive approximately 157.4 million shares of our common stock, subject
(if additional cash capital contributions are made to Crusader) to the
issuance of additional shares up to approximately 14.3 million on the
basis of one additional share for each three additional dollars of capital
contributed. After the completion of the merger, we would have
between 183.8 million to 198.1 million shares outstanding, depending on
the aggregate amount of any additional capital contributions to Crusader
and prior to the effectiveness of a planned one-for-two reverse stock
split of our common stock. Moreover, after the completion of
the merger, we will change our name to “Crusader Energy Group Inc.,” and
our current management will resign so that the Crusader management team
can run the combined company.
|
Our
Properties
The table
below lists and summarizes our acreage by program as of December 31, 2007. This
table excludes acreage in which our interests are limited to royalty and
overriding royalty interests.
|
Program
|
|
Developed
Acreage
|
|
Undeveloped
Acreage
|
|
Total
Acreage
|
|
Weighted
Average Remaining Lease Term
|
|
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
|
|
|
North
|
|
|
2,820
|
|
|
662
|
|
|
6,757
|
|
|
4,486
|
|
|
9,577
|
|
|
5,148
|
|
|
0.75
years*
|
|
|
Southeast
|
|
|
1,250
|
|
|
505
|
|
|
19,262
|
|
|
9,480
|
|
|
20,512
|
|
|
9,985
|
|
|
2.5
years
|
|
|
Southwest
|
|
|
640
|
|
|
147
|
|
|
51,342
|
|
|
51,342
|
|
|
51,982
|
|
|
51,489
|
|
|
7.3
years
|
|
|
Total
|
|
|
4,710
|
|
|
1,314
|
|
|
77,361
|
|
|
65,308
|
|
|
82,071
|
|
|
66,622
|
|
|
|
|
* Certain
leases in the North Program area have drilling commitments that, if not met,
could result in the loss of undrilled acreage.
The
majority of our leases in the North are held by production; however, on those
leases not held by production, the remaining lease term is 1.25
years
.
North
Program
The North
Program is located in Cooke, Denton, Montague and Wise Counties in Texas and was
the primary focus of our drilling and production activities during 2005 and
2006. This region of the Barnett Shale (our North Program area) is defined by
the following characteristics:
|
|
·
|
Our
Operated Wells:
|
33
gross /approximately 13 net completed
|
|
|
·
|
Our
Non-Operated Wells:
|
9
gross / approximately 1.2 net completed wells (excludes overriding royalty
interest wells)
|
|
|
·
|
Barnett
Thickness:
|
Up
to 1,000 feet
|
|
|
·
|
Drilling
Depth:
|
7,500
to 9,000 feet
|
|
|
·
|
Drilling
Method:
|
Vertical
and horizontal
|
|
|
·
|
Production
Characteristics:
|
High
Btu natural gas and associated liquids
|
|
|
·
|
Fracture
Stimulation:
|
3
to 5 stage, medium volume
|
|
|
·
|
Key
Considerations:
|
Lower
risk drilling, multiple pay zones, high liquid content, operations in high
Btu conditions and access to equipment and
services
|
Southeast
Program
The
Southeast Program is located in Hill and Ellis Counties in Texas. In
2007, the Southeast Program became the primary focus of our drilling and
production activities. During fiscal 2005, we completed the
processing of a three-dimensional seismic survey of 4.3 square miles that
includes property leased by us in northern Hill County (the “Survey”). Based on
the Survey, we selected our first site for drilling on the property. During
fiscal 2006, we entered into a joint exploration agreement covering
approximately 17,200 gross acres in Hill County, Texas. As provided
in the agreement, we and the other party to the joint exploration agreement
generally completed a cross-assignment to each other of 50% interests in certain
properties
In 2007,
Westside drilled and completed the following wells under this Joint Exploration
Agreement in Hill County:
|
Well
Name
|
|
First
Gas Sales
|
|
IP
(MMCF/D spot)
|
|
|
|
|
|
|
|
Ellison
Estate #1H
|
|
May
2007
|
|
1.9
|
|
Primula
South #2H
|
|
August
2007
|
|
2.1
|
|
Ellison
Estate #2H
|
|
November
2007
|
|
1.9
|
|
Ellison
Estate #3H
|
|
November
2007
|
|
1.5
|
|
Ellison
Estate #4H
|
|
January
2008
|
|
2.2
|
Additionally,
under the joint exploration agreement, the Bearden #1HR well was spudded
and the 3D seismic shoot was completed in the Cornerstone
Area.
Westside
Energy had several nonoperated wells that were drilled and completed in Johnson
County as a result of our transaction with Gulftex Operating Company/TD
Energy Services. Westside participated in the drilling and completion
of Devon’s Alfred Kennon #3H, #4H, #5H, #6H, and #7H. Also, Westside
participated in the drilling and completion of the Conoco Schmidt #3H and
#4H.
The Hill
and Ellis Counties region of the Barnett Shale (our Southeast Program area) is
defined by the following characteristics:
|
|
·
|
Our
Operated Wells:
|
6
gross / 3.5 net drilling and completing
|
|
|
·
|
Barnett
Thickness:
|
200
to 400 feet
|
|
|
·
|
Drilling
Depth:
|
7,000
to 9,000 feet
|
|
|
·
|
Drilling
Method:
|
Horizontal
|
|
|
·
|
Production
Characteristics:
|
Natural
gas
|
|
|
·
|
Fracture
Stimulation:
|
4
to 6 stage, high volume
|
|
|
·
|
Key
Considerations:
|
Lower
risk drilling, contiguous shale completion, three-dimensional seismic
control, cost control and infrastructure access
|
|
|
·
|
Our
Nonoperated wells:
|
8
gross / 2.9 net
|
Southwest
Program
The
Southwest Program is located in Comanche, Coryell, Hamilton, Mills and Lampasas
Counties in Texas. Drilling in this area by others has been primarily vertical,
although horizontal drilling technology has recently been utilized. The terms of
the leases covering this area expire sufficiently far enough into the future
(especially considering renewal options in our favor) that we are not
constrained to drill in this area in the near future.
This region of the
Barnett Shale (our Southwest Program area) is defined by the following
characteristics:
|
|
·
|
Barnett
Thickness:
|
130
to 220 feet
|
|
|
·
|
Drilling
Depth:
|
3,000
to 4,000 feet
|
|
|
·
|
Drilling
Method:
|
Vertical
and horizontal
|
|
|
·
|
Production
Characteristics:
|
Natural
gas and oil
|
|
|
·
|
Fracture
Stimulation:
|
6
to 8 stage, low volume
|
|
|
·
|
Key
Considerations:
|
Multiple
pay zones, expansion area with limited production, associated water
production and infrastructure
access
|
Our
Business Strategy
Our goal
is to increase shareholder value by finding and developing natural gas and oil
reserves at costs that provide an attractive rate of return on our investments.
The principal elements of our business strategy are:
|
|
*
|
Develop Our
Existing Properties
.
We intend to create near-term reserve and production growth from numerous
drilling locations identified on our Barnett Shale acreage. The structure
and the continuous natural gas and oil accumulation of the Barnett Shale
and the expected long-life production and reserves of these properties
enhance our opportunities for long-term
profitability.
|
|
|
*
|
Pursue
Selective Acquisitions and Joint Ventures
. Due to our asset base and
technical expertise, we believe we are well positioned to pursue selective
acquisitions and attract industry joint venture partners. We expect to
pursue additional natural gas and oil properties in the Barnett
Shale.
|
|
|
*
|
Reduce Unit
Costs Through Economies of Scale and Efficient Operations
. As we continue to increase our
natural gas and oil production and develop our existing properties, we
expect that our unit cost structure will benefit from economies of scale.
With respect to our operations in the Barnett Shale, we anticipate
reducing unit costs by greater utilization of our existing infrastructure
over a larger number of wells. We seek to exert control over costs and
timing in our exploration, development and production activities through
our operating activities and relationships with our joint venture
partners.
|
Our Competitive
Strengths
We
believe that the key competitive strengths of our company include:
|
|
*
|
Significant
Production Growth Opportunities
. We have acquired a large
acreage position with very favorable lease terms in a region where
drilling and production activities by other exploration and production
companies continue to increase. Based on continued drilling success within
our acreage position, we expect to increase our reserves, production and
cash flow.
|
|
|
*
|
Experienced
Management Team with Strong Technical Capability
. Our senior management team and
Board of Directors have considerable public company experience, industry
experience and technical expertise in engineering, geoscience and field
operations, with an average of more than 20 years of experience in the
natural gas and oil industry. Our in-house technical personnel have
extensive experience in the Barnett Shale, including horizontal drilling,
completion and fracture stimulation techniques and
technologies.
|
|
|
*
|
Incentivized
Management Ownership
. The equity ownership of our
directors and executive officers is strongly aligned with that of our
stockholders. As of March 31, 2008, our directors and executive officers
owned approximately 13.5% of our outstanding common stock. In addition,
the compensation arrangements for our directors and executive officers are
heavily weighted toward future performance based equity payments rather
than cash.
|
Drilling
Activity
The
following table sets forth the results of our drilling activities during the
fiscal years ended December 31, 2005, 2006 and 2007:
|
Drilling
Activity
|
|
|
|
|
Gross
Wells
|
|
Net
Wells
|
|
|
Year
|
|
Total
|
|
Producing
|
|
Dry
|
|
Total
|
|
Producing
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
Exploratory
|
|
|
5.0
|
|
|
5.0
|
|
|
--
|
|
|
2.9
|
|
|
2.9
|
|
|
--
|
|
|
2006
Exploratory
|
|
|
5.0
|
|
|
5.0
|
|
|
--
|
|
|
2.8
|
|
|
2.8
|
|
|
--
|
|
|
2007
Exploratory
|
|
|
1.0
|
|
|
1.0
|
|
|
--
|
|
|
0.5
|
|
|
--
|
|
|
--
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
Development
|
|
|
1.0
|
|
|
1.0
|
|
|
--
|
|
|
0.5
|
|
|
0.5
|
|
|
--
|
|
|
2006
Development
|
|
|
4.0
|
|
|
4.0
|
|
|
--
|
|
|
2.0
|
|
|
2.0
|
|
|
--
|
|
|
2007
Development
|
|
|
13.0
|
|
|
13.0
|
|
|
--
|
|
|
5.4
|
|
|
5.4
|
|
|
--
|
|
Production
Information
Net
Production, Average Sales Price and Average Production Costs
(Lifting)
The table
below sets forth the net quantities of oil and gas production (net of all
royalties, overriding royalties and production due to others) attributable to us
for the fiscal years ended December 31, 2005, 2006 and 2007, and the average
sales prices, average production costs and direct lifting costs per unit of
production.
|
|
|
Years
Ended December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Production
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(MBbls)
|
|
|
4
|
|
|
|
23
|
|
|
|
24
|
|
|
Gas
(MMcf)
|
|
|
47
|
|
|
|
360
|
|
|
|
795
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Sales Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(per Bbl)
|
|
$
|
57.94
|
|
|
$
|
61.93
|
|
|
$
|
72.71
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
(per Mcf)
|
|
$
|
7.35
|
|
|
$
|
5.92
|
|
|
$
|
5.64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Production Cost (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per
equivalent (Bbl of oil)
|
|
$
|
33.35
|
|
|
$
|
84.92
|
|
|
$
|
42.61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Lifting Costs (2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per
equivalent (Bbl of oil)
|
|
$
|
9.00
|
|
|
$
|
21.43
|
|
|
$
|
12.93
|
|
|
(1)
|
Production
costs include all operating expenses, depreciation, depletion and
amortization, lease operating expenses and all associated taxes. Does not
include impairment.
|
|
(2)
|
Direct
lifting costs do not include impairment expense or depreciation, depletion
and amortization.
|
Productive
Wells and Acreage
Gross
and Net Productive Wells, Developed Acres, and Overriding Royalty
Interests
Leasehold Interests - Productive
Wells and Developed Acres:
The tables below sets forth our leasehold
interests in productive and shut-in gas wells, and in developed acres, at
December 31, 2007:
|
|
|
Producing
and Shut-In
|
|
|
Prospect
|
|
Gross
Gas
|
|
Net
(1) Gas
|
|
|
|
|
|
|
|
|
|
Barnett
Shale
|
|
|
73
|
|
|
19.6
|
|
|
(1)
|
A net well is deemed to exist
when the sum of fractional ownership working interests in gross wells
equals one. The number of net wells is the sum of the fractional working
interests owned in gross wells expressed as whole numbers and fractions
thereof.
|
|
|
|
Developed
Acreage Table
Developed
Acres (1)
|
|
|
Prospect
|
|
Gross
(2)
|
|
Net
(3)
|
|
|
|
|
|
|
|
|
|
Barnett
Shale
|
|
|
4,710
|
|
|
1,314
|
|
|
(1)
|
Consists of acres spaced or
assignable to productive
wells.
|
|
(2)
|
A gross acre is an acre in which
a working interest is owned. The number of gross acres is the total number
of acres in which a working interest is
owned.
|
|
(3)
|
A net acre is deemed to exist
when the sum of fractional ownership working interests in gross acres
equals one. The number of net acres is the sum of the fractional working
interests owned in gross acres expressed as whole numbers and fractions
thereof.
|
Undeveloped
Acreage
Leasehold Interests Undeveloped
Acreage:
The following table sets forth our leasehold interest in
undeveloped acreage at December 31, 2007:
|
|
|
Undeveloped
Acreage Table
|
|
|
Prospect
|
|
Gross
|
|
Net
|
|
|
|
|
|
|
|
|
|
Barnett
Shale
|
|
|
77,361
|
|
|
65,801
|
|
Gas
Delivery Commitments
None.
Reserve
Information - Oil and Gas Reserves:
LaRoche
Petroleum Consultants, Ltd. evaluated our oil and gas reserves attributable to
our properties at December 31, 2007. Reserve calculations by independent
petroleum engineers involve the estimation of future net recoverable reserves of
oil and gas and the timing and amount of future net revenues to be received
therefrom. Those estimates are made using sales prices estimated to be in effect
as of the date of such reserve estimates and are held constant throughout the
life of the properties (except to the extent a contract specifically provides
for escalation). Estimated quantities of proved reserves and future net revenues
therefrom are affected by oil and gas prices, which have fluctuated widely in
recent years. Moreover, these estimates are based on numerous factors, many of
which are variable, uncertain and beyond the control of the producer. Reserve
estimators are required to make numerous, subjective judgments based upon
professional training, experience and educational background. As a result,
estimates of different engineers, including those used by us, may vary. The
extent and significance of the judgments are sufficient to render reserve
estimates inherently imprecise, since reserve revenues and operating expenses
may not occur as estimated. Moreover, it is common for the actual production and
revenues later received to vary from earlier estimates. Estimates made in the
first few years of production from a property are generally not as reliable as
later estimates based on a longer production history. Reserve estimates based
upon volumetric analysis are inherently less reliable than those based on
lengthy production history. Also, potentially productive gas wells may not
generate revenue immediately due to lack of pipeline connections and potential
development wells may have to be abandoned due to unsuccessful completion
activities. Hence, reserve estimates may vary from year to year. Based on the
preceding, the reserve data set forth in this Annual Report must be viewed only
as estimates and not as exact information.
Estimated Proved/Developed and
Undeveloped Reserves:
The following tables set forth our estimated proved
developed and proved undeveloped oil and gas reserves for the years ended
December 31, 2005, 2006 and 2007. See Note 16 to the Consolidated Financial
Statements and the above discussion.
|
|
|
Developed
and Undeveloped Reserves
|
|
|
|
|
Developed
|
|
Undeveloped
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(Bbls)
|
|
|
|
|
|
|
|
|
December
31, 2005
|
|
|
85,206
|
|
|
11,200
|
|
|
96,406
|
|
|
December
31, 2006
|
|
|
85,385
|
|
|
64,230
|
|
|
149,615
|
|
|
December
31, 2007
|
|
|
72,058
|
|
|
141,494
|
|
|
213,552
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
(Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
December
31, 2005
|
|
|
1,191,699
|
|
|
272,000
|
|
|
1,463,699
|
|
|
December
31, 2006
|
|
|
3,277,562
|
|
|
2,557,473
|
|
|
5,835,035
|
|
|
December
31, 2007
|
|
|
9,616,208
|
|
|
7,771,379
|
|
|
17,387,587
|
|
For
information concerning the standardized measure of discounted future net cash
flows, estimated future net cash flows and present values of such cash flows
attributable to our proved oil and gas reserves as well as other reserve
information, see Note 16 to the Consolidated Financial Statements.
Oil and Gas Reserves Reported to
Other Agencies:
We did not file any estimates of total proved net oil or
gas reserves with, or include such information in reports to, any federal
authority or agency since the beginning of the fiscal year ended December 31,
2007.
Title
to Properties
Our
properties are subject to customary royalty interests, liens under indebtedness,
liens incident to operating agreements and liens for current taxes and other
burdens, including mineral encumbrances and restrictions. Our current credit
facility is also secured by a first lien on a large part of our assets. We do
not believe that any of these burdens materially interferes with the use of our
properties in the operation of our business.
We
believe that we have satisfactory title to or rights in all of our producing
properties. As is customary in the natural gas and oil industry, minimal
investigation of title is made at the time of acquisition of undeveloped
properties. In most cases, we investigate title and obtain title opinions from
counsel or have title reviewed by certified landmen only when we acquire
producing properties or before we begin drilling operations.
Sale
of Natural Gas and Oil
We do not
intend to refine our natural gas or oil production. We expect to sell all or
most of our production to a small number of purchasers in a manner consistent
with industry practices at prevailing rates by means of long-term sales
contracts. We are developing a market with purchasers such as end-users, local
distribution companies, and natural gas brokers. We have several long-term
purchase contracts, and can readily find other purchasers, if needed. In areas
where there is no practical access to pipelines, oil is trucked to storage
facilities.
Markets
and Marketing
The
natural gas and oil industry has experienced rising prices in recent years. As a
commodity, global natural gas and oil prices respond to macro-economic factors
affecting supply and demand. In particular, world oil prices have risen in
response to political unrest and supply uncertainty in Iraq, Venezuela, Nigeria
and Iran, and increasing demand for energy in rapidly growing economies, notably
India and China. Due to rising world prices and the consequential impact on
supply, North American prospects have become more attractive. Escalating
conflicts in the Middle East and the ability of OPEC to control supply and
pricing are some of the factors negatively impacting the availability of global
supply. In contrast, increased costs of steel and other products used to
construct drilling rigs and pipeline infrastructure, as well as higher drilling
and well-servicing rig rates, negatively impact domestic supply.
Our
market is affected by many factors beyond our control, such as the availability
of other domestic production, commodity prices, the proximity and capacity of
natural gas and oil pipelines, and general fluctuations of global and domestic
supply and demand. Although we have entered into few sales contracts at this
time, we do not anticipate difficulty in finding additional sales
opportunities.
Natural
gas and oil sales prices are negotiated based on factors such as the spot price
for gas or posted price for oil, price regulations, regional price variations,
distances from wells to pipelines, well pressure, and estimated reserves. Many
of these factors are outside our control. Natural gas and oil prices have
historically experienced high volatility, related in part to ever-changing
perceptions within the industry of future supply and demand.
Competition
The
natural gas and oil industry is intensely competitive and, as an early-stage
company, we must compete against larger companies that may have greater
financial and technical resources than we and substantially more experience in
our industry. These competitive advantages may better enable our competitors to
sustain the impact of higher exploration and production costs, natural gas and
oil price volatility, productivity variances between properties, overall
industry cycles and other factors related to our industry. Their advantage may
also negatively impact our ability to acquire prospective properties, develop
reserves, attract and retain quality personnel and raise capital.
Natural
Gas and Oil Regulation
Regulation of Transportation and
Sale of Natural Gas
.
Historically,
the transportation and sale for resale of natural gas in interstate commerce
have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas
Policy Act of 1978 and regulations issued under those Acts by the Federal Energy
Regulatory Commission, or FERC. In the past, the federal government has
regulated the prices at which natural gas could be sold. While sales by
producers of natural gas can currently be made at uncontrolled market prices,
Congress could reenact price controls in the future. Deregulation of wellhead
natural gas sales began with the enactment of the Natural Gas Policy Act. In
1989, Congress enacted the Natural Gas Wellhead Decontrol Act. The Decontrol Act
generally removed all Natural Gas Act and Natural Gas Policy Act price and
non-price controls affecting wellhead sales of natural gas effective January 1,
1993.
Since the
mid-1980s, the FERC has endeavored to make natural gas transportation more
accessible to natural gas buyers and sellers on an open and non-discriminatory
basis. The FERC has stated that open access policies are necessary to improve
the competitive structure of the interstate natural gas pipeline industry and to
create a regulatory framework that will put natural gas sellers into more direct
contractual relations with natural gas buyers by, among other things, unbundling
the sale of natural gas from the sale of transportation and storage services.
Beginning in 1992, the FERC issued Order No. 636 and a series of related orders
to implement its open access policies. As a result of the Order No. 636 program,
the marketing and pricing of natural gas have been significantly altered. The
interstate pipelines' traditional role as wholesalers of natural gas has been
eliminated and replaced by a structure under which pipelines provide
transportation and storage services on an open access basis to others who buy
and sell natural gas. Although the FERC's orders do not directly regulate
natural gas producers, they are intended to foster increased competition within
all phases of the natural gas industry.
In 2000,
the FERC issued Order No. 637 and subsequent orders, which imposed a number of
additional reforms designed to enhance competition in natural gas markets. Among
other things, Order No. 637 changed FERC regulations relating to scheduling
procedures, capacity segmentation, penalties, rights of first refusal and
information reporting. We cannot accurately predict whether the FERC's actions
will achieve the goal of increasing competition in markets in which our natural
gas is sold. Additional proposals and proceedings that might affect the natural
gas industry are pending before the FERC and the courts. Therefore, we cannot
provide any assurance that the less stringent regulatory approach recently
established by the FERC will continue. However, we do not believe that any
action taken will affect us in a way that materially differs from the way it
affects other natural gas producers.
Intrastate
natural gas transportation and gathering of natural gas is subject to regulation
by state regulatory agencies. The basis for intrastate regulation of natural gas
transportation and gathering and the degree of regulatory oversight and scrutiny
given to intrastate natural gas transportation and gathering rates and services
varies from state to state. Insofar as such regulation within a particular state
will generally affect all shippers on intrastate natural gas pipelines and
gatherers within the state on a comparable basis, we believe that the regulation
of similarly situated intrastate natural gas transportation and gathering in any
state in which we operate and ship natural gas on an intrastate basis will not
affect our operations in any way that is of material difference from those of
our competitors.
Regulation of Transportation and
Sale of Oil
.
Sales of
oil, condensate and natural gas liquids are not currently regulated and are made
at negotiated prices. Nevertheless, Congress could enact (or, in some cases,
reenact) price controls in the future.
Our sales
of oil are affected by the availability, terms and cost of transportation. The
transportation of oil in common carrier pipelines is also subject to rate
regulation. The FERC regulates interstate oil pipeline transportation rates
under the Interstate Commerce Act. In general, interstate oil pipeline rates
must be cost-based, although settlement rates agreed to by all shippers are
permitted and market-based rates may be permitted in certain circumstances.
Effective January 1, 1995, the FERC implemented regulations establishing an
indexing system (based on inflation) for transportation rates for oil that
allowed for an increase or decrease in the cost of transporting oil to the
purchaser. A review of these regulations by the FERC in 2000 was successfully
challenged on appeal by an association of oil pipelines. On remand, the FERC in
February 2003 increased the index slightly, effective July 2001. Intrastate oil
pipeline transportation rates are subject to regulation by state regulatory
commissions. The basis for intrastate oil pipeline regulation, and the degree of
regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies
from state to state. Insofar as effective interstate and intrastate rates are
equally applicable to all comparable shippers, we believe that the regulation of
oil transportation rates will not affect our operations in any way that is of
material difference from those of our competitors.
Further,
interstate and intrastate common carrier oil pipelines must provide service on a
non-discriminatory basis. Under this open access standard, a common carrier must
offer the same terms and rates to all similarly-situated shippers requesting
service. When oil pipelines operate at full capacity, access is governed by
pro-rationing provisions set forth in the pipelines' published tariffs.
Accordingly, we believe that access to oil pipeline transportation services will
generally be available to us to the same extent as to our
competitors.
Environmental
Regulation
We are
subject to stringent federal, state and local laws, that, among other things,
govern the issuance of permits to conduct exploration, drilling and production
operations, the amounts and types of materials that may be released into the
environment, the discharge and disposition of waste materials, the remediation
of contaminated sites and the reclamation and abandonment of wells, sites and
facilities. Numerous government departments issue rules and regulations to
implement and enforce such laws, which are often difficult and costly to comply
with and which carry substantial civil and even criminal penalties for failure
to comply. Some laws, rules and regulations relating to protection of the
environment may, in certain circumstances, impose strict liability for
environmental contamination, rendering a person liable for environmental damages
and cleanup costs without regard to negligence or fault on the part of such
person. Other laws, rules and regulations may restrict the rate of oil and
natural gas production below the rate that would otherwise exist or even
prohibit exploration and production activities in sensitive areas. In addition,
state laws often require various forms of remedial action to prevent pollution,
such as closure of inactive pits and plugging of abandoned wells. The regulatory
burden on the oil and natural gas industry increases our cost of doing business
and consequently affects our profitability. These costs are considered a normal,
recurring cost of our on-going operations. Our domestic competitors are
generally subject to the same laws and regulations. We believe that we are in
substantial compliance with current applicable environmental laws and
regulations and that continued compliance with existing requirements will not
have a material adverse impact on our operations.
The
Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA,
imposes liability, without regard to fault, on certain classes of persons that
are considered to be responsible for the release of a "hazardous substance" into
the environment. These persons include the current or former owner or operator
of the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of hazardous substances. Under CERCLA,
such persons may be subject to joint and several liability for the cost of
investigating and cleaning up hazardous substances that have been released into
the environment, for damages to natural resources and for the cost of certain
health studies. In addition, companies that incur liability frequently also
confront third-party claims because it is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damage allegedly caused by hazardous substances or other pollutants
released into the environment from a polluted site.
The
Federal Solid Waste Disposal Act, as amended by the Resource Conservation and
Recovery Act of 1976, or RCRA, regulates the generation, transportation,
storage, treatment and disposal of hazardous wastes and can require cleanup of
hazardous waste disposal sites. RCRA currently excludes drilling fluids,
produced waters and other wastes associated with the exploration, development or
production of oil and natural gas from regulation as "hazardous
waste." State law usually regulates disposal of such non-hazardous
natural gas and oil exploration, development and production wastes. Other wastes
handled at exploration and production sites or used in the course of providing
well services may not fall within this exclusion. Moreover, stricter standards
for waste handling and disposal may be imposed on the oil and natural gas
industry in the future. From time to time, legislation is proposed in Congress
that would revoke or alter the current exclusion of exploration, development and
production wastes from the RCRA definition of "hazardous wastes," thereby
potentially subjecting such wastes to more stringent handling, disposal and
cleanup requirements. If such legislation were enacted, it could have a
significant impact on our operating costs, as well as the oil and natural gas
industry in general. The impact of future revisions to environmental laws and
regulations cannot be predicted.
Our
operations are also subject to the Clean Air Act, or CAA, and comparable state
and local requirements. Amendments to the CAA were adopted in 1990 and contain
provisions that may result in the gradual imposition of certain pollution
control requirements with respect to air emissions from our operations. We may
be required to incur certain capital expenditures in the future for air
pollution control equipment in connection with obtaining and maintaining
operating permits and approvals for air emissions. However, we believe our
operations will not be materially adversely affected by any such requirements,
and the requirements are not expected to be any more burdensome to us than to
other similarly situated companies involved in oil and natural gas exploration
and production activities.
The
Federal Water Pollution Control Act of 1972, as amended, or the Clean Water Act,
imposes restrictions and controls on the discharge of produced waters and other
wastes into navigable waters. Permits must be obtained to discharge pollutants
into state and federal waters and to conduct construction activities in waters
and wetlands. Certain state regulations and the general permits issued under the
Federal National Pollutant Discharge Elimination System program prohibit the
discharge of produced waters and sand, drilling fluids, drill cuttings and
certain other substances related to the oil and natural gas industry into
certain coastal and offshore waters, unless otherwise authorized. Further, the
EPA has adopted regulations requiring certain oil and natural gas exploration
and production facilities to obtain permits for storm water discharges. Cost may
be associated with the treatment of wastewater or developing and implementing
storm water pollution prevention plans. The Clean Water Act and comparable
state statutes provide for civil, criminal and administrative penalties for
unauthorized discharges for oil and other pollutants and impose liability on
parties responsible for those discharges for the cost of cleaning up any
environmental damage caused by the release and for natural resource damages
resulting from the release. We believe that our operations comply in all
material respects with the requirements of the Clean Water Act and state
statutes enacted to control water pollution.
Underground
injection is the subsurface placement of fluid through a well, such as the
re-injection of brine produced and separated from oil and natural gas
production. The Safe Drinking Water Act of 1974, as amended, establishes a
regulatory framework for underground injection, with the main goal being the
protection of usable aquifers. The primary objective of injection well operating
requirements is to ensure the mechanical integrity of the injection apparatus
and to prevent migration of fluids from the injection zone into underground
sources of drinking water. Hazardous-waste injection well operations are
strictly controlled and certain wastes, absent an exemption, cannot be injected
into underground injection control wells. In Texas, no underground injection may
take place except as authorized by permit or rule.
Statutes
that provide protection to animal and plant species and that may apply to our
operations include the National Environmental Policy Act, the Oil Pollution Act,
the Emergency Planning and Community Right-to-Know Act, Research and Sanctuaries
Act, the Fish and Wildlife Coordination Act, the Fishery Conservation and
Management Act, the Migratory Bird Treaty Act and the National Historic
Preservation Act. These laws and regulations may require the acquisition of a
permit or other authorization before construction or drilling commences and may
limit or prohibit construction, drilling and other activities on certain lands
lying within wilderness or wetlands and other protected areas and impose
substantial liabilities for pollution resulting from our operations. The permits
required for our various operations are subject to revocation, modification and
renewal by issuing authorities.
Employees
As of
March 31, 2008, we had nine full-time employees.
Facilities
Our
principal executive offices are located in Dallas, Texas, where we lease
approximately 5,000 square feet. This lease terminates July 31,
2008.
IT
EM 3. LEGAL PROCEEDINGS
We are
not now a party to any legal proceeding requiring disclosure in accordance with
the rules of the U.S. Securities and Exchange Commission. In the
future, we may become involved in various legal proceedings from time to time,
either as a plaintiff or as a defendant, and either in or outside the normal
course of business. We are not now in a position to determine when (if ever)
such a legal proceeding may arise. If we ever become involved in a legal
proceeding, our financial condition, operations, or cash flows could be
materially and adversely affected, depending on the facts and circumstances
relating to such proceeding.
IT
EM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS.
None.
PART
II.
ITE
M 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS AND SMALL BUSINESS ISSUER PURCHASES OF EQUITY
SECURITIES.
Our
common stock is listed on the AMEX under the symbol “WHT.” The following table
sets forth the high and low trading prices per share of our common stock on the
AMEX for the periods stated.
|
|
HIGH
|
|
LOW
|
|
|
|
|
|
|
|
|
2007
|
|
|
|
|
|
Fourth
Quarter
|
|
$
|
3.30
|
|
|
$
|
1.74
|
|
|
Third
Quarter
|
|
|
3.62
|
|
|
|
2.45
|
|
|
Second
Quarter
|
|
|
3.91
|
|
|
|
2.25
|
|
|
First
Quarter
|
|
|
2.81
|
|
|
|
1.28
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fourth
Quarter
|
|
$
|
2.50
|
|
|
$
|
1.04
|
|
|
Third
Quarter
|
|
|
3.41
|
|
|
|
2.30
|
|
|
Second
Quarter
|
|
|
3.90
|
|
|
|
2.30
|
|
|
First
Quarter
|
|
|
4.18
|
|
|
|
2.89
|
|
As of
March 27, 2008, we had approximately 193 record holders of our common
stock.
We have
never paid cash dividends, and have no intentions of paying cash dividends in
the foreseeable future.
EQUITY
COMPENSATION PLANS
We have
the following three equity compensation plans for our directors, officers,
employees and consultants pursuant to which options, rights or shares may be
granted or issued:
|
|
*
|
our
2007 Equity Incentive Plan (the “Equity
Plan”);
|
|
|
*
|
our
2004 Consultant Compensation Plan (the “Consultant Plan”);
and
|
|
|
*
|
our
2005 Director Stock Plan (the “Director
Plan”).
|
The
following table provides information as of December 31, 2007 with respect to our
compensation plans (including individual compensation arrangements), under which
securities are authorized for issuance aggregated as to (i) compensation plans
previously approved by stockholders, and (ii) compensation plans not previously
approved by stockholders:
Equity
Compensation Plan Information
|
|
|
Number
of securities to be issued upon exercise of outstanding options, warrants
and rights
|
|
Weighted-average
exercise price of outstanding options, warrants and rights
|
|
Number
of securities remaining available for future issuance under equity
compensation plans (excluding securities reflected in column
(a))
|
|
|
Plan
category
|
|
(a)
|
|
(b)
|
|
(c)
|
|
|
|
|
|
|
|
|
|
|
|
Equity
compensation plans approved by security holders
|
|
|
-0-
|
|
|
-0-
|
|
|
1,605,669
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
compensation plans not approved by security holders
|
|
|
-0-
|
|
|
-0-
|
|
|
2,954,592 (2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
-0-
|
|
|
-0-
|
|
|
4,560,261
|
|
|
|
(1)
|
Of
these shares, 1,605,669 shares remain available for issuance under our
2007 Equity Incentive Plan
|
|
|
(2)
|
Of these shares, 2,551,839 shares
and 402,753 shares remain available for issuance under our 2004 Consultant
Compensation Plan and our 2005 Director Stock Plan,
respectively.
|
Our
2004 Consultant Compensation Plan
The
following is a description of the material features of the Consultant
Plan
General
. On April 14, 2004,
our Board of Directors approved the Consultant Plan. The Consultant Plan
provides for the grant of shares of our Common Stock to certain outside
consultants of ours who assist in the development and success of our business to
reward them for their services and to encourage them to continue to provide
services to us.
Administration
. Our Board of
Directors administers the Consultant Plan.
Eligibility
. The Board of
Directors has substantial discretion pursuant to the Consultant Plan to
determine the persons to whom shares of Common Stock are awarded and the amounts
and restrictions imposed in connection therewith. Under the Consultant Plan,
awards may be made only to individuals who are outside consultants, or
directors, officers, partners or employees of outside consultants, of us or a
subsidiary. The number of consultants employed by us varies.
Shares Subject to the Consultant
Plan
. Three million (3,000,000) shares of Common Stock are authorized to
be awarded pursuant to the Consultant Plan, 500,000 of which were registered
with the Securities and Exchange Commission. Any shares awarded and later
forfeited are again subject to award or sale under the Consultant Plan. Awards
may be made pursuant to the Consultant Plan until no further shares are
available for issuance or until April 15, 2014, whichever occurs
first.
Previous Awards
. We have
awarded 448,161 shares of Common Stock pursuant to the Consultant Plan as of
December 31, 2007.
Restrictions
. The Board may,
in its discretion, place restrictions and conditions in connection with any
particular award of shares pursuant to the Consultant Plan. Shares awarded
subject to a condition are, in general, non-assignable until the condition is
satisfied.
Anti-dilution
. The Consultant
Plan carries certain anti-dilution provisions concerning stock dividends, stock
splits, consolidations, mergers, re-capitalizations and
reorganizations.
Amendment and Termination
. Our
Board of Directors may terminate or amend the Consultant Plan in any respect at
any time, except no action of our Board of Directors, or our stockholders, may,
without the consent of a participant, alter or impair such participant's rights
under any restricted shares previously granted.
Term
. The Consultant Plan
shall expire on April 15, 2014 unless sooner terminated except as to restricted
share grants outstanding on that date.
Federal Income Tax
Consequences
. The following brief summary of the principal Federal income
tax consequences of transactions under the Consultant Plan is based on current
Federal income tax laws. This summary is not intended to constitute tax advice
and, among other things, does not address possible state or local tax
consequences. Accordingly, a participant in the Consultant Plan should consult a
tax advisor with respect to the tax aspects of transactions under the Consultant
Plan.
Unrestricted Stock Grants
. The
tax consequences of unrestricted stock awards will depend on the specific terms
of each award.
Restricted Stock Grants
. Upon
receipt of restricted stock, a participant generally will recognize taxable
ordinary income when the shares cease to be subject to restrictions in an amount
equal to the fair market value of the shares at such time. However, no later
than 30 days after a participant receives the restricted stock, the participant
may elect to recognize taxable ordinary income in an amount equal to the fair
market value of the shares at the time of receipt. Provided that the election is
made in a timely manner, when the restrictions on the shares lapse, the
participant will not recognize any additional income. If the participant
forfeits the shares to us (e.g., upon the participant's termination prior to
expiration of the restriction period), the participant may not claim a deduction
with respect to the income recognized as a result of the election. Dividends
paid with respect to shares of restricted stock generally will be taxable as
ordinary income to the participant at the time the dividends are
received.
Tax Consequences to Us
. We
generally will be entitled to a deduction at the same time and in the same
amount as a participant recognizes ordinary income, subject to the limitations
imposed under Section 162(m).
Tax Withholding
. We have the
right to deduct withholding taxes from any payments made pursuant to the
Consultant Plan or to make such other provisions as it deems necessary or
appropriate to satisfy our obligations to withhold federal, state or local
income or other taxes incurred by reason of payment or the issuance of Common
Stock under the Consultant Plan or the lapse of restrictions on grants upon
which restrictions have been placed.
Our
2005 Director Stock Plan
The
following is a description of the material features of the Director
Plan.
General.
Effective March 30,
2005, our Board of Directors adopted the Director Plan. The Director Plan
provides for the grant of shares of our Common Stock to non-employee members of
the Board of Directors to provide them with incentives to work hard for our
success.
Administration.
Our Board of
Directors administers the Director Plan.
Eligibility.
Under the
Director Plan, awards may be made only to members of our Board of Directors who
are not employees of us or any of our affiliates (“Non-Employee
Directors”).
Shares Subject to the Director Plan.
Five hundred thousand (500,000) shares of Common Stock are authorized to
be awarded pursuant to the Director Plan.
Awards may be made
pursuant to the Director Plan until no further shares are available for issuance
or until March 30, 2015, whichever occurs first.
Awards.
Each Non-Employee
Director receives an award of 12,666 shares of Common Stock when he or she first
becomes a director. Of these shares, 4,222 are unrestricted, and the remaining
8,444 shares are restricted, with one-half of them vesting one year after the
award and with one-half of them vesting two years after the award, provided, in
both cases, that the related person is still a director of ours on the vesting
dates. In addition to the initial grant, each Non-Employee Director receives an
annual award of 2,650 shares of our Common Stock. Of these shares, 884 are
unrestricted, and the remaining 1,766 are restricted, with one-half of them
vesting one year after the award and with one-half of them vesting two years
after the award, provided, in both cases, that the related person is still a
director of ours on the vesting dates. We have awarded 97,247 shares of Common
Stock pursuant to the Director Plan as of December 31, 2007.
Restrictions.
The restricted
shares comprising a grant are non-assignable until such shares are vested and no
longer subject to forfeiture.
Anti-dilution.
The Director
Plan carries certain anti-dilution provisions concerning stock dividends, stock
splits, consolidations, mergers, re-capitalizations and reorganizations.
Amendment and Termination.
Our
Board of Directors may terminate or amend the Director Plan in any respect at
any time, provided that no alteration or amendment may be made without the
approval of stockholders if such approval is required by applicable law or stock
exchange rule.
Term.
The Director Plan shall
expire on March 30, 2015 unless sooner terminated except as to restricted share
grants outstanding on that date.
Federal Income Tax Consequences.
The following brief summary of the principal Federal income tax
consequences of transactions under the Director Plan is based on current Federal
income tax laws. This summary is not intended to constitute tax advice and,
among other things, does not address possible state or local tax consequences.
Accordingly, a participant in the Director Plan should consult a tax advisor
with respect to the tax aspects of transactions under the Director
Plan.
Unrestricted Stock Grants.
The
tax consequences of the unrestricted shares comprising a grant will depend on
the specific terms of each award.
Restricted Stock Grants.
With
regard to the restricted shares, a participant generally will recognize taxable
ordinary income when the shares cease to be subject to restrictions in an amount
equal to the fair market value of the shares at such time. However, no later
than 30 days after a participant receives the restricted shares, the participant
may elect to recognize taxable ordinary income in an amount equal to the
fair market value of the shares at the time of receipt. Provided that the
election is made in a timely manner, when the restrictions on the shares lapse,
the participant will not recognize any additional income. If the participant
forfeits the shares (e.g., upon the participant's termination prior to
expiration of the restriction period), the participant may not claim a deduction
with respect to the income recognized as a result of the election. Dividends
paid with respect to shares of restricted shares generally will be taxable as
ordinary income to the participant at the time the dividends are received.
Tax Consequences to Us.
We
generally will be entitled to a deduction at the same time and in the same
amount as a participant recognizes ordinary income, subject to the limitations
imposed under Section 162(m).
Tax Withholding.
We
have the right to deduct
withholding taxes from any payments made pursuant to the Director Plan or to
make such other provisions as it deems necessary or appropriate to satisfy our
obligations to withhold federal, state or local income or other taxes incurred
by reason of payment or the issuance of Common Stock under the Director Plan or
the lapse of restrictions on grants upon which restrictions have been
place.
ITE
M 6. MANAGEMENT'S DISCUSSION AND ANALYSIS.
The
following discussion and analysis of our financial condition and results of
operations should be read in conjunction with our consolidated financial
statements and related notes included elsewhere in this Annual Report. In
addition to historical information, the discussion in this report contains
forward-looking statements that involve risks and uncertainties. Actual results
could differ materially from those anticipated by these forward-looking
statements due to factors including, but not limited to, those factors set forth
under "Risk Factors" and elsewhere in this Annual Report.
Overview
We are an
independent natural gas and oil exploration and production company based in
Dallas, Texas with operations in the Barnett Shale in the Fort Worth Basin
located in north central Texas. We have been successful in identifying and
acquiring acreage positions where vertical and horizontal drilling, advanced
fracture stimulation and enhanced recovery technologies create the possibility
of economically developing and producing natural gas and oil reserves from the
Barnett Shale. We have assembled a portfolio of large, predominantly undeveloped
leasehold interests in the Barnett Shale, which we believe positions us for
significant long-term growth in proved natural gas and oil reserves and
production. As of December 31, 2007, we owned natural gas and oil leasehold
interests in approximately 82,071 gross (66,622 net)
acres. Approximately 94% of our gross acreage and 98% of our net
acreage are undeveloped. In addition, we own working interests in 73 gross (19.6
net) wells in the Barnett Shale.
As of
December 31, 2007, we had estimated net proved reserves of 17.4 Bcfe. We have
identified approximately 500 drilling locations on our existing acreage. Our
estimated net proved reserves are located on approximately 5% of our net
acreage. Based on our drilling results to date and third-party results in
adjacent areas, we believe that our remaining undeveloped acreage in the Barnett
Shale has substantial current commercial potential, and we plan to exploit that
potential through our drilling program.
Recent
Developments
On
December 31, 2007, we entered into a Contribution Agreement (the “Contribution
Agreement”) pursuant to which we agreed to a merger with the privately held
Crusader Energy Group (“Crusader”). The merger is subject to our
stockholders’ approval. If the merger is approved and completed, the
ultimate equity owners of Crusader will receive approximately 157.4 million
shares of our common stock, subject (if additional cash capital contributions
are made to Crusader) to the issuance of additional shares up to approximately
14.3 million on the basis of one additional share for each three additional
dollars of capital contributed. After the completion of the merger,
we would have between 183.8 million and 198.1 million shares outstanding,
depending on the aggregate amount of any additional capital contributions to
Crusader and prior to the effectiveness of a planned one-for-two reverse stock
split of our common stock. Moreover, after the completion of the
merger, we will change our name to “Crusader Energy Group Inc.,” and our current
management will resign so that the Crusader management team can run the combined
company.
During
the first few months of 2007, we have focused our exploration and production
activities primarily on our one rig drilling program with our joint exploration
agreement partner in Hill County which includes the first of our wells in the
southern part of the county. We have also continued our development
activities on the properties acquired last fall from GulfTex and T.D.
Energy. We anticipate that the pace of operations activity will remain at
about the current level until the proposed merger described in detail in the
preliminary proxy statement is closed. Integration and transition planning
for this transaction is ongoing.
Critical
Accounting Policies and Estimates
Our
discussion of our financial condition and results of operations is based on the
information reported in our financial statements. The preparation of our
financial statements requires us to make assumptions and estimates that affect
the reported amounts of assets, liabilities, revenues and expenses as well as
the disclosure of contingent assets and liabilities as of the date of our
financial statements. We base our assumptions and estimates on historical
experience and other sources that we believe to be reasonable at the time.
Actual results may vary from our estimates due to changes in circumstances,
weather, politics, global economics, mechanical problems, general business
conditions and other factors. Our significant accounting policies are detailed
in Note 1 to our financial statements included in this Annual Report. We have
outlined below certain of these policies that have particular importance to
the reporting of our financial condition and results of operations and that
require the application of significant judgment by our management.
Key
Definitions
Proved
reserves, as defined by the SEC, are the estimated quantities of crude oil,
condensate, natural gas and natural gas liquids that geological and engineering
data demonstrate with reasonable certainty are recoverable in future years from
known reservoirs under existing economic and operating conditions. Valuations
include consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future conditions. Prices do not
include the effect of derivative instruments, if any, entered into by
us.
Proved
developed reserves are those reserves expected to be recovered through existing
equipment and operating methods. Additional oil and gas volumes expected to be
obtained through the application of fluid injection or other improved recovery
techniques for supplementing the natural forces and mechanisms of primary
recovery are included as proved developed reserves only after testing of a pilot
project or after the operation of an installed program has confirmed through
production response that increased recovery will be achieved.
Proved
undeveloped reserves are those reserves that are expected to be recovered from
new wells on non-drilled acreage, or from existing wells where a relatively
major expenditure is required for re-completion. Reserves on non-drilled acreage
are limited to those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves for other
non-drilled units are claimed only where it can be demonstrated with certainty
that there is continuity of production from the existing productive
formation.
Estimation
of Reserves
Volumes
of reserves are estimates that, by their nature, are subject to revision. The
estimates are made using all available geological and reservoir data as well as
production performance data. There are numerous uncertainties in estimating
crude oil and natural gas reserve quantities, projecting future production rates
and projecting the timing of future development expenditures. Natural gas and
oil reserve engineering must be recognized as a subjective process of estimating
underground accumulations of natural gas and oil that cannot be measured in an
exact way. Estimates of independent engineers that we use may differ from those
of other engineers. The accuracy of any reserve estimate is a function of the
quantity and quality of available data and of engineering and geological
interpretation and judgment. Accordingly, future estimates are subject to change
as additional information becomes available.
The most
critical estimate we make is the engineering estimate of proved oil and gas
reserves. This estimate affects the application of the successful efforts method
of accounting, the calculation of depreciation, depletion and amortization of
oil and gas properties and the estimate of any impairment of our oil and gas
properties. It also affects the estimated lives used to determine asset
retirement obligations. In addition, the estimates of proved oil and gas
reserves are the basis for the related standardized measure of discounted future
net cash flows.
Revenue
Recognition
Oil and
gas revenues are recognized when production is sold to a purchaser at a fixed or
determinable price, when delivery has occurred and title has transferred..
Westside did not have any material imbalance position in terms of natural gas
volumes or values at December 31, 2007. Westside would account for
any gas imbalances using the entitlement method.
Successful
Efforts Accounting
We
utilize the successful efforts method to account for our natural gas and oil
operations. Under this method, all costs associated with natural gas and oil
lease acquisitions, successful exploratory wells and all development wells are
capitalized. Producing properties are amortized on a
unit-of-production basis over the remaining life of proved developed reserves
and proved reserves on a lease basis. Unproved leasehold costs are capitalized
pending the results of exploration efforts. Exploration costs, including
geological and geophysical expenses, exploratory dry holes and delay rentals,
are expensed when incurred.
Impairment
of Properties
We review
our proved properties for potential impairment at the lease level when
management determines that events or circumstances indicate that the
recorded carrying value of any of the properties may not be recoverable. Such
events include a projection of future natural gas and oil reserves that will be
produced from a lease, the timing of this future production, future costs to
produce the natural gas and oil, and future inflation levels. If the carrying
amount of an asset exceeds the sum of the discounted estimated future net cash
flows, we recognize impairment expense equal to the difference between the
carrying value and the fair market value of the asset, which is estimated to be
the expected discounted value of future net cash flows from reserves, without
the application of any estimate of risk. We cannot predict the amount of
impairment charges that may be recorded in the future. Unproved leasehold costs
are reviewed periodically and impairment is recognized to the extent, if any,
that the cost of the property has been impaired.
Derivatives
All
derivative instruments are recorded on the balance sheet at their fair value.
Changes in the fair value of each derivative are recorded each period in current
earnings or other comprehensive income, depending on whether the derivative is
designated as part of a hedge transaction and, if it is, the type of hedge
transaction. To make this determination, management formally documents the
hedging relationship and its risk−management objective and strategy for
undertaking the hedge, the hedging instrument, the item, the nature of the risk
being hedged, how the hedging instrument's effectiveness in offsetting the
hedged risk will be assessed, and a description of the method of measuring
ineffectiveness. This process includes linking all derivatives that are
designated as cash−flow hedges to specific cash flows associated with assets and
liabilities on the balance sheet or to specific forecasted
transactions.
Westside
also formally assesses, both at the hedge's inception and on an ongoing basis,
whether the derivatives that are used in hedging transactions are highly
effective in offsetting cash flows of hedged items. A derivative that is highly
effective and that is designated and qualifies as a cash−flow hedge has its
changes in fair value recorded in other comprehensive income to the extent that
the derivative is effective as a hedge. Any other changes determined to be
ineffective do not qualify for cash−flow hedge accounting and are reported
currently in earnings.
Westside
discontinues cash−flow hedge accounting when it is determined that the
derivative is no longer effective in offsetting cash flows of the hedged item;
the derivative expires or is sold, terminated, or exercised; the derivative is
redesignated as a non−hedging instrument because it is unlikely that a forecast
transaction will occur; or management determines that designation of the
derivative as a cash−flow hedge instrument is no longer appropriate. In
situations in which cash−flow hedge accounting is discontinued, Westside
continues to carry the derivative at its fair value on the balance sheet and
recognizes any subsequent changes in its fair value in earnings.
When the
criteria for cash−flow hedge accounting are not met, realized gains and losses
(i.e., cash settlements) are recorded in other income and expense in the
Statements of Operations. Similarly, changes in the fair value of the derivative
instruments are recorded as unrealized gains or losses in the Statements of
Operations. In contrast, cash settlements for derivative instruments that
qualify for hedge accounting are recorded as additions to or reductions of oil
and gas revenues while changes in fair value of cash flow hedges are recognized,
to the extent the hedge is effective, in other comprehensive income until the
hedged item is recognized in earnings.
Stock-Based
Compensation
Compensation
expense has been recorded for common stock grants based on the fair value of the
common stock on the measurement date. Statement of Financial Accounting
Standards No. 123R, "Share-Based Payments," or "SFAS No. 123R," establishes
standards for accounting for transactions in which an entity exchanges its
equity instruments for goods and services. SFAS No. 123R focuses primarily on
accounting for transactions in which an entity obtains employee services in
share-based payment transactions. SFAS No. 123R requires that the fair value of
such equity instruments be recognized as expense in the historical financial
statements as services are performed. SFAS No. 123R was effective for us as of
the beginning of 2006 and has had no impact on our financial statements, because
the only equity compensation that we have previously made is in the form of
grants of common stock, which are recorded at fair value. Standards of
accounting for transactions in which an entity exchanges its equity instruments
for goods and services by a consultant or contractor are further governed by
EITF 18-69 by which the grant is measured at the fair value of the stock
exchanged and the associated expense is recorded to the nature of the good or
service rendered. Any difference between the fair value of the stock
exchanged and the fair value of services is recorded at either a prepaid expense
or a discount on the value of the services rendered.
Results of Operations -
Year ended December 31, 2007 compared to the year ended December 31,
2006
Revenues.
Revenues
from sales of oil and natural gas were $6,440,087 in the 2007 as compared
to $3.915,209 in 2006. This increase in revenues reflects the impact
of increased sales volumes and prices for oil and natural
gas. Oil sales volumes increased from an average of 63 to 66
barrels per day, and average oil sales prices increased from $61.93 to $69.79
per barrel. Natural gas sales volumes increased from an average of
988 thousand cubic feet per day (MCF/D) to 2.2 million cubic feet per day
(MMCF/D) while average natural gas sales prices increased from $5.92 to $5.99
per MCF.
Expenses.
Operating
expenses increased to $19,323,136 in 2007 from $17,096,540 in
2006. This change comprises an increase in production, exploration,
general and administrative, and impairment expense and a decrease in depletion,
depreciation, and amortization expense.
|
|
·
|
Production
Expense.
The increase in production expense to
$2,386,951 for 2007 from $1,779,192 for 2006 is a function of increased
well maintenance costs and increased severance taxes related to
increased production operations activities associated with an increase in
the number of producing wells.
|
|
|
·
|
Exploration
Expense.
The increase in exploration expense to
$2,107,222 for 2007 from $0 for 2006 reflects the purchase of additional
three-dimensional seismic data covering leaseholds in Hill and Ellis
Counties and the right to shoot seismic in Mills County, as well as
additional seismic activites related to prospects, all of which was
expensed immediately under successful efforts
accounting.
|
|
|
·
|
General and Administrative
Expense.
General and administrative expense increased to
$5,970,874 for 2007 from $5,296,723 for 2006. General and
administrative expense for 2007 includes $590,087 of expenses for legal,
accounting, and other professional fees associated with our proposed
merger with Crusader Energy.
|
|
|
·
|
Depreciation, depletion and
amortization expense.
The decrease in depreciation,
depletion and amortization expense to $4,338,743 for 2007 from $5,710,295
for 2006 reflects the substantial increase in proved reserves at December
31, 2007 despite increased 2007 oil and gas
production.
|
|
|
·
|
Impairment
Charges.
The increase in the impairment charge to $4,519,346
in December 2007 from $4,310,330 in December 2006 reflects, primarily,
2007 development costs for two wells which exceeded their fair values,
based on their estimated reserves, and, to a significantly lesser extent,
older wells whose proved reserves, hence their fair values, have
declined. In December 2007, impairment charges of $4,362,030
were taken against nine developed properties and $157,316 against unproved
leases. In December 2006 impairment charges of $4,085,234 were
taken against twelve developed leases and $225,096 against unproved
leases.
|
Operating Loss.
As a
result of the above described revenues and expenses, we incurred an operating
loss of $12,883,049 in 2007 as compared to an operating loss of $13,181,331 in
2006.
Other Income (Expense).
Other
income and expense items in 2007 include $358,926 in interest income and
$3,253,514 in interest expense. 2006 results included $225,619 in
interest income and $956,200 in interest expense.
Interest expense
increased in 2007 as a result of higher debt balances due to additional funding
from the Senior Secured Loan facility in March 2007 and the Knight Note facility
in September 2007.
Net Loss.
We incurred a net
loss of $15,777,637, or $.71 per share, in 2007 as compared to a net loss of
$13,911,912, or $0.66 per share, in 2006.
Liquidity
and Capital Resources
Sales of
Equity
. On November 9, 2007, we completed a private placement
in which we sold 2,456,140 shares of our common stock, at $2.85 per share, to
three investors resulting in gross proceeds of approximately $7.0
million. The three investors are related parties, and the number of
shares they purchased and the consideration we received for these share are as
follows:
|
|
1)
|
Knight
Energy Group II, LLC (a Crusader entity), 1,192,983 shares,
$3,400,002
|
|
|
2)
|
Spindrift
Partners, LP (controlled by Wellington), 576,857 shares,
$1,644,042
|
|
|
3)
|
Spindrift
Investor (Bermuda), LP (controlled by Wellington), 686,300 shares,
$1,955.955
|
We
incurred various miscellaneous costs believed to be immaterial in connection
with the consummation of this placement.
Cash and Cash Equivalents
. As
of December 31, 2007, we had cash, cash equivalents and marketable securities of
approximately $6.9 million, representing an increase of $1.8 million from
December 31, 2006.
Hedging
. In the first quarter
of 2006, we began hedging a portion of our production in accordance with the
terms of our senior secured credit facility then in effect. All of
the positions in this initial hedging program have settled. In
January 2007, we entered into swap contracts covering 240,000 MMBtu of
natural gas to be produced from
February
2007 through December 2008. The price stated in the swap contracts
was $7.45 per MMBtu.
In
January 2007, we also entered into swap contracts covering 5,000 barrels of oil
to be produced from March 2007 through November 2007. The price
stated in the swap contracts was $55.50 per barrel.
During the first
quarter of 2008, we entered into two additional hedging transactions in the form
of costless collars. Both of these programs cover natural gas to
be produced for a one-year period starting in March 2008, in the case of the
first of these 2008 programs, and starting in April 2008 in the case
of the second of these programs. The first 2008 program has a floor
of $8.00 and a cap of $10.35 per MMBtu, while the second of these collars has a
floor of $9.00 and a cap of $12.50 per MMBtu.
Senior Secured Financing
.
During March 2007, we entered into our current senior credit facility. The
credit facility was provided by four private investment funds managed by
Wellington Management, LLC, which is the largest beneficial holder of our
outstanding common stock
.
The credit facility:
|
|
*
|
initially
provided $25 million in funds, which were advanced in their entirety upon
completion of the credit facility;
|
|
|
*
|
is secured by a first lien on all
of the oil and gas properties comprising our Southeast and Southwest
Programs;
|
|
|
*
|
grants to the lenders the right
to receive a lien in any and all of the proceeds received upon the sale of
a property comprising our North Program or any subsequent property
acquired with such proceeds;
|
|
|
*
|
bears annual interest at 10.0%,
or (in the case of default) 12.0%
annually;
|
|
|
*
|
grants to the lenders a three
percent (3.0%) overriding royalty interest (proportionately reduced to our
working interest) in all oil and gas produced from the
properties then comprising our Southeast and Southwest
Programs;
|
|
|
*
|
contains limiting operating
covenants;
|
|
|
*
|
contains events of default
arising from failure to timely repay principal and interest or comply with
certain covenants or a change of control;
and
|
|
|
*
|
requires the repayment of the
outstanding balance of the loan in March
2009.
|
Moreover,
on September 20, 2007, we entered into an additional, unsecured $8.0 million
credit facility with Knight Energy Group II, LLC (“Knight”) (a Crusader entity),
as lender. This credit facility:
|
|
*
|
initially
provided $2.6 million in funds, $2.0 million of which were used to fund
the cash portion of the purchase price for an
acquisition;
|
|
|
*
|
requires
a detailed Authority for Expenditure (an "AFE") as a condition to a draw
against the facility;
|
|
|
*
|
bears
interest at an annual rate equal to the one-month London Interbank Offer
Rate (LIBOR) plus 5.0%;
|
|
|
*
|
limits
the use of the proceeds from the facility for certain
purposes;
|
|
|
*
|
contains
limiting operating covenants;
|
|
|
*
|
contains
events of default arising from failure to timely repay principal and
interest or comply with certain covenants;
and
|
|
|
*
|
requires
the repayment of the outstanding balance of the loan in March
2009.
|
We
believe that our available cash will be sufficient to enable us to pursue our
business plans until the anticipated time of the consummation of the merger with
Crusader Energy Group. However, if this merger shall fail to occur
(or the consummation is delayed significantly) for any reason, we believe that
we would be constrained to pursue either one of two alternatives. Our
first alternative would be to seek additional financing to continue our business
plans at their current level. We currently do not have any binding
commitments for any additional financing. We cannot assure anyone
that additional financing will be available to us when needed or, if available,
that it can be obtained on commercially reasonable terms. If we do
not obtain additional financing in the event of the failure of or significant
delay in the consummation of the merger, our second alternative would be to
reduce our current level of operations. Pursuing this second
alternative may constrain us to attempt to sell some of our assets. However, we
cannot assure anyone that we will be able to find interested buyers or that the
funds received from any such sale would be adequate to fund our activities even
at a reduced level. However, we believe that, with our current access
to capital, we could operate at some reduced level until our outstanding
institutional indebtedness becomes due in March 2009. However, if we
do not obtain additional financing, we may not be able to satisfy this
indebtedness. If this were to occur, we could default on such
indebtedness, in which case our lenders could foreclose on a large part of our
assets and exercise other creditor rights, which could result in the loss of all
or nearly all of the value of our outstanding equity and bring our operations to
an end. See
"ITEMS 1
and 2. DESCRIPTION OF BUSINESS AND PROPERTIES - RISK FACTORS -
Our credit
facilities, one of which is secured by a large part of our assets, features
limiting operating covenants and requires substantial future payments, expose us
to certain risks and may adversely affect our ability to operate our
business
."
ITE
M 7. FINANCIAL STATEMENTS.
The
report of our Independent Auditors appears at Page F-1 hereof, and our Financial
Statements appear at Pages F-2 through F-16 hereof.
ITE
M 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE.
Not
applicable.
ITE
M 8A(T). INTERNAL CONTROL OVER FINANCIAL
REPORTING.
Evaluation
of Disclosure Controls and Procedures
As of the
end of the period covered by this Annual Report, management performed, with the
participation of our Chief Executive Officer and Chief Financial Officer, an
evaluation of the effectiveness of our disclosure controls and procedures as
defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Our disclosure
controls and procedures are designed to ensure that information required to be
disclosed in the report we file or submit under the Exchange Act is recorded,
processed, summarized, and reported within the time periods specified in the
SEC’s rules, and that such information is accumulated and communicated to our
management including our Chief Executive Officer and our Chief Financial
Officer, to allow timely decisions regarding required disclosures. Based
on the evaluation and the identification of the material weaknesses in internal
control over financial reporting described below, our Chief Executive Officer
and our Chief Financial Officer concluded that, as of December 31, 2007, the
Company’s disclosure controls and procedures were not effective.
Management’s
Report on Internal Control Over Financial Reporting
Management
is responsible for establishing and maintaining adequate internal control over
financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange
Act. Internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements in accordance with GAAP.
Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projection of
any evaluation of effectiveness to future periods is subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may
deteriorate.
Management
has conducted, with the participation of our Chief Executive Officer and our
Chief Financial Officer, an assessment, including testing of the effectiveness,
of our internal control over financial reporting as of December 31, 2007.
Management’s assessment of internal control over financial reporting was
conducted using the criteria in
Internal Control over Financial
Reporting – Guidance for Smaller Public Companies
issued by the Committee
of Sponsoring Organizations of the Treadway Commission (“COSO”).
A
material weakness is a deficiency, or a combination of deficiencies, in internal
control over financial reporting, such that there is a reasonable possibility
that a material misstatement of the Company’s annual or interim financial
statements will not be prevented or detected on a timely
basis.
Based on
this assessment, management has concluded that our internal control over
financial reporting was not effective as of December 31, 2007, based on
Internal Control over Financial
Reporting – Guidance for Smaller Public Companies
issued by
COSO.
Our Chief
Executive Officer and our Chief Financial Officer concluded that we have
material weaknesses in our internal control over financial reporting because we
do not adequately monitor or maintain support for the work of our specialized
oil and gas consultant as it relates to the books and records. We lack
segregation of duties in the processing of our transactions, restricting access
to our general ledger and safeguarding of cash (relates to check handling; the
Company does not handle any currency), which is due to the inherent resource
limitations of small companies.
Remediation of
Material Weaknesses in Internal Control Over Financial
Reporting
We plan
to rectify these deficiencies on consummation of a business combination with an
operating company that, due to its substantially increased size, will
have the resources to perform the specialized oil and gas accounting and
implement the appropriate segregation of duties.
Changes in Internal Control Over
Financial Reporting
There
were no changes in our internal control over financial reporting during the
fourth quarter ended December 31, 2007 that materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting.
This
annual report does not include an attestation report of the company's registered
public accounting firm regarding internal control over financial reporting.
Management's report was not subject to attestation by the company's registered
public accounting firm pursuant to temporary rules of the Securities and
Exchange Commission that permit the company to provide only management's report
in this annual report
ITEM
8B. OTHER INF
ORMA
TION
Not
applicable.
PART
III.
ITEM
9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS, CONTROL PERSONS
AND CORPORATE GOVERNANCE; COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE
ACT
General
Most of
the information required by this Item is set forth under the captions “Proposal
6 – ELECTION OF DIRECTORS,” “Compliance with Section 16(a) of the Exchange Act,”
and “SECURITY OWNERSHIP OF PRINCIPAL STOCKHOLDERS - Audit Committee” in the
Company's definitive Proxy Statement to be filed with the Securities and
Exchange Commission and is incorporated herein by this reference as if set forth
in full.
Code
of Ethics
On March
31, 2004, we adopted a Code of Ethics that applies to our principal executive
officer, principal financial officer and principal accounting officer, as well
as others working on our behalf. The Code of Ethics is posted on our website,
and anyone can obtain a copy of the Code of Ethics by contacting us at the
following address: 3131 Turtle Creek Blvd, Suite 1300, Dallas, Texas 75219,
attention: Chief Executive Officer, telephone: (214) 522-8990. The first such
copy will be provided without charge. We will post on our website any amendments
to the Code of Ethics, as well as any waivers that are required to be disclosed
by the rules of either the Securities and Exchange Commission or the National
Association of Securities Dealers.
ITEM
10. EXECUTIVE COMPENSATION.
The
information required by this Item is set forth under the captions “Compensation
of Our Executive Officers,” “Director Compensation,” in the Company's definitive
Proxy Statement to be filed with the Securities and Exchange Commission and is
incorporated herein by this reference as if set forth in full.
ITEM
11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
The
information required by this Item is set forth under the captions “SECURITY
OWNERSHIP OF PRINCIPAL STOCKHOLDERS” in the Company's definitive Proxy Statement
to be filed with the Securities and Exchange Commission and is incorporated
herein by this reference as if set forth in full.
ITEM
12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND
DIRECTOR INDEPENDENCE.
Some of
the information required by this Item is set forth under the captions “CERTAIN
RELATED TRANSACTIONS” in the Company's definitive Proxy Statement to be filed
with the Securities and Exchange Commission and is incorporated herein by this
reference as if set forth in full.
Director
Independence
Our
common stock is listed for trading on the American Stock Exchange (the “AMEX”).
Accordingly, we use the standards established by the AMEX for determining
whether each of our directors is “independent.” We have determined that, each of
Keith D. Spickelmier, John T. Raymond and Herbert C. Williamson is currently an
“independent” director in accordance with the AMEX independence standards,
although Mr. Spickelmier did not meet these standards of independence during the
first two months of 2007. The AMEX rules generally require that a listed
company’s Board of Directors comprise a majority of independent directors.
However, these rules provide that a “small business issuer” need only maintain a
Board of Directors comprised of at least 50% independent directors. Based on our
current “small business issuer” status and the preceding exemption, we
maintained a Board of Directors comprised of 50% independent directors, until
the time that Jimmy D. Wright resigned from his seat on the Board in April 2007.
Since the time of Mr. Wright’s resignation, we have maintained a Board of
Directors comprising a majority of independent directors.
Mr.
Spickelmier also served on our Audit Committee during a portion of fiscal 2007
at a time when he did not meet the AMEX independence standards. The AMEX rules
generally require that a listed company’s Audit Committee comprise at least
three members, each of whom must be independent. However, these rules provide
that one director who is not independent but meets certain other requirements
may be appointed to the Audit Committee, if the Board of Directors, under
exceptional and limited circumstances, determines that membership on the
committee by the individual is required by the best interests of the issuer and
its stockholders. Mr. Spickelmier was appointed to our Audit Committee on the
basis of the preceding exemption. In determining that Mr. Spickelmier’s
appointment to our Audit Committee was required by our and our stockholders’
best interests, the Board of Directors considered Mr. Spickelmier's background
and expertise, the fact that Mr. Spickelmier would soon again meet the AMEX’s
standards of independence, and the anticipated improved performance of our Audit
Committee that would result from a greater number of members serving on such
committee.
In
addressing the question as to Mr. Spickelmier’s independence in view of AMEX
standards, the Board of Directors considered the $120,000 in annual fees paid to
Mr. Spickelmier for serving as our Chairman of the Board, and the Board of
Directors determined that such fees did not create a material relationship that
would interfere with Mr. Spickelmier’s exercise of independent
judgment.
PART
IV.
ITEM
13. EXHIBITS.
The
following exhibits are filed with this Annual Report or are incorporated herein
by reference:
|
Exhibit
No.
|
Description
|
|
|
|
|
2.01
|
Contribution
Agreement dated December 31, 2007, by and among us, Knight Energy Group I
Holding Co., LLC, Knight Energy Group II Holding Company, LLC, Knight
Energy Management Holding Company, LLC, Hawk Energy Fund I Holding
Company, LLC, RCH Energy Opportunity Fund I, L.P. David D. Le Norman,
Crusader Energy Group Holding Co., LLC, Knight Energy Group, LLC, Knight
Energy Group II, LLC, Knight Energy Management, LLC, Hawk Energy Fund I,
LLC, RCH Upland Acquisition, LLC, Crusader Management Corporation, and
Crusader Energy Group, LLC is incorporated herein by reference from our
Current Report on Form 8-K (SEC File No. 0-49837) filed with the SEC on
January 7, 2008, Exhibit 2.1.
|
|
3.01
|
Our
Restated Articles of Incorporation is incorporated herein by reference
from our Quarterly Report on Form 10-QSB for the quarter ended June 30,
2004 (SEC File No. 0-49837), Exhibit 3.01.
|
|
3.02
|
Our
Second Amended and Restated Bylaws are incorporated herein by reference
from our Current Report on Form 8-K (SEC File No. 0-49837) filed with the
SEC on January 7, 2008, Exhibit 3(ii).1.
|
|
3.04
|
Article
of Merger of Westside Energy Subsidiary Corporation with and into us,
whereby we changed our corporate name to "Westside Energy Corporation" is
incorporated herein by reference from our Annual Report on Form 10-KSB for
the year ended December 31, 2003 (SEC File No. 0-49837), Exhibit
3.04
|
|
4.01
|
Specimen
Common Stock Certificate is incorporated herein by reference from
Pre-effective Amendment No. 1 to our Registration Statement on Form SB-2
(SEC File No. 333-120659) filed December 23, 2004, Exhibit
4.01.
|
|
10.01
|
Warrant
to Purchase our common stock issued in the name of Keith D. Spickelmier is
incorporated herein by reference from our Current Report on Form 8-K (SEC
File No. 0-49837) filed with the SEC on March 1, 2004, Exhibit
10.04
|
|
10.02
|
Warrant
to Purchase our common stock issued in the name of Keith D. Spickelmier is
incorporated herein by reference from our Registration Statement on Form
SB-2 (SEC File No. 333-120659) filed November 22, 2004, Exhibit
10.10.
|
|
10.03
|
Warrant
to Purchase our common stock issued in the name of Sterne, Agee &
Leach, Inc. - filed herewith
|
|
10.04
|
Warrant
to Purchase our common stock issued in the name of William Charles
O'Malley, Jr. - filed herewith
|
|
10.05
|
Agreement
dated April 12, 2005 between us and EBS Oil and Gas Partners Production
Company, L.P. is incorporated herein by reference from our Current Report
on Form 8-K (SEC File No. 0-49837) filed with the SEC on April 22, 2005,
Exhibit 10.01.
|
|
10.06
|
Employment
Agreement dated December 8, 2005 between us and Douglas G. Manner is
incorporated herein by reference from our Current Report on Form 8-K (SEC
File No. 0-49837) filed with the SEC on December 31, 2007, Exhibit
10.04.
|
|
10.07
|
First
Amendment dated effective March 31, 2006 to Employment Agreement with
Douglas G. Manner is incorporated herein by reference from our Current
Report on Form 8-K (SEC File No. 0-49837) filed with the SEC on December
31, 2007, Exhibit 10.05.
|
|
10.08
|
Second
Amendment dated April 4, 2007 but effective as of January 1, 2007 to
Employment Agreement with Douglas G. Manner is incorporated herein by
reference from our Current Report on Form 8-K (SEC File No. 0-49837) filed
with the SEC on December 31, 2007, Exhibit 10.06.
|
|
10.09
|
Third
Amendment dated effective as of December 7, 2007 to Employment Agreement
with Douglas G. Manner is incorporated herein by reference from our
Current Report on Form 8-K (SEC File No. 0-49837) filed with the SEC on
December 31, 2007, Exhibit 10.07.
|
|
10.10
|
Agreement
dated May 3, 2005 between us and Sean J. Austin is incorporated herein by
reference from our Current Report on Form 8-K (SEC File No. 0-49837) filed
with the SEC on December 31, 2007, Exhibit 10.08.
|
|
10.11
|
First
Amendment dated effective January 1, 2006 to Employment Agreement with
Sean J. Austin is incorporated herein by reference from our Current Report
on Form 8-K (SEC File No. 0-49837) filed with the SEC on December 31,
2007, Exhibit 10.09.
|
|
10.12
|
Second
Amendment dated effective September 1, 2006 to Employment Agreement with
Sean J. Austin is incorporated herein by reference from our Current Report
on Form 8-K (SEC File No. 0-49837) filed with the SEC on December 31,
2007, Exhibit 10.10.
|
|
10.13
|
Third
Amendment dated April 4, 2007 but effective as of January 1, 2007 to
Employment Agreement with Sean J. Austin is incorporated herein by
reference from our Current Report on Form 8-K (SEC File No. 0-49837) filed
with the SEC on December 31, 2007, Exhibit 10.11.
|
|
10.14
|
Fourth
Amendment dated effective as of December 7, 2007 to Employment Agreement
with Sean J. Austin is incorporated herein by reference from our Current
Report on Form 8-K (SEC File No. 0-49837) filed with the SEC on December
31, 2007, Exhibit 10.12.
|
|
10.15
|
Unrestricted
Stock Award Agreement between us and Douglas G. Manner dated effective as
of December 7, 2007 to Employment Agreement with Sean J. Austin is
incorporated herein by reference from our Current Report on Form 8-K (SEC
File No. 0-49837) filed with the SEC on December 31, 2007, Exhibit
10.13.
|
|
10.16
|
Unrestricted
Stock Award Agreement between us and Sean J. Austin dated effective as of
December 7, 2007 to Employment Agreement with Sean J. Austin is
incorporated herein by reference from our Current Report on Form 8-K (SEC
File No. 0-49837) filed with the SEC on December 31, 2007, Exhibit
10.14.
|
|
10.17
|
Unrestricted
Stock Award Agreement between us and Keith D. Spickelmier dated effective
as of December 7, 2007 to Employment Agreement with Sean J. Austin is
incorporated herein by reference from our Current Report on Form 8-K (SEC
File No. 0-49837) filed with the SEC on December 31, 2007, Exhibit
10.15.
|
|
10.18
|
Form
of Indemnification Agreements separately entered into by us, on the one
hand, and Keith D. Spickelmier, Douglas G. Manner, Craig S. Glick, John T.
Raymond, Herbert C. Williamson and Sean J. Austin, on the other
hand
|
|
10.19
|
Purchase
and Sale Agreement dated November 30, 2005 between us, on the one hand,
and Kelly K. Buster, James I. Staley, Enexco, Inc., the Class B Limited
Partners of EBS, and EBS Oil & Gas Partners Production GP, LLC, on the
other hand, is incorporated herein by reference from our Annual Report on
Form 10-KSB for the year ended December 31, 2006 (SEC File No. 0-49837),
Exhibit 10.11.
|
|
10.20
|
Joint
Exploration Agreement dated June 26, 2006 between us and Forest Oil
Corporation is incorporated herein by reference from our Annual Report on
Form 10-KSB for the year ended December 31, 2006 (SEC File No. 0-49837),
Exhibit 10.14.
|
|
10.21
|
Letter
Amendment dated April 4, 2007 to Joint Exploration Agreement with Forest
Oil Corporation is incorporated herein by reference from our Current
Report on Form 8-K (SEC File No. 0-49837) filed with the SEC on December
31, 2007, Exhibit 10.16.
|
|
10.22
|
Purchase
and Sale Agreement dated November 9, 2006, between Westside Energy
Production Company, L.P. and Cimmarron Gathering, LP is incorporated
herein by reference from our Annual Report on Form 10-KSB for the year
ended December 31, 2006 (SEC File No. 0-49837), Exhibit
10.15.
|
|
10.23
|
Consulting
Agreement dated April 4, 2007 but effective as of May 1, 2007 between us
and Jimmy D. Wright is incorporated herein by reference from our Annual
Report on Form 10-KSB for the year ended December 31, 2006 (SEC File No.
0-49837), Exhibit 10.19.
|
|
10.24
|
Credit
Agreement dated as of March 23, 2007 between us and certain of our
subsidiaries, on the one hand, and certain lenders with Spindrift
Partners, L.P. as a lender and as administrative agent, on the other hand,
is incorporated herein by reference from our Current Report on Form 8-K
(SEC File No. 0-49837) filed with the SEC on March 27, 2007, Exhibit
10.01.
|
|
10.25
|
Asset
Purchase and Sale Agreement dated September 25, 2007 by GulfTex Operating,
Inc. and TD Energy Services, Inc., on the one hand, and us, on the other
hand, is incorporated herein by reference from our Current Report on Form
8-K (SEC File No. 0-49837) filed with the SEC on September 26, 2007,
Exhibit 10.03.
|
|
10.26
|
$8,000,000.00
Revolving Note dated September 20, 2007 and executed by us in favor of
Knight Energy Group II, LLC is incorporated herein by reference from our
Current Report on Form 8-K (SEC File No. 0-49837) filed with the SEC on
September 26, 2007, Exhibit 10.02.
|
|
10.27
|
First
Amendment of Credit Agreement dated as of March 23, 2007 with Spindrift
Partners, L.P. as a lender and as administrative agent is incorporated
herein by reference from our Current Report on Form 8-K (SEC File No.
0-49837) filed with the SEC on September 26, 2007, Exhibit
10.03.
|
|
10.28
|
First
Modification dated as of November 12, 2007 to $8,000,000.00 Revolving Note
in favor of Knight Energy Group II, LLC is incorporated herein by
reference from our Current Report on Form 8-K (SEC File No. 0-49837) filed
with the SEC on November 15, 2007, Exhibit 10.01.
|
|
10.29
|
Purchase
Agreement dated as of November 9, 2007 by and between us, on the one hand,
and Spindrift Partners, L.P., Spindrift Investors (Bermuda), L.P.,
and Knight Energy Group II, LLC,
on the other hand, is incorporated herein by reference from our
Current Report on Form 8-K (SEC File No. 0-49837) filed with the SEC on
November 15, 2007, Exhibit 10.02.
|
|
10.30
|
Registration Rights Agreement dated November 12,
2007 by and
between Registrant, on the one hand, and Spindrift
Partners LP, Spindrift
Investors (Bermuda) L.P., and Knight
Energy Group II, LLC, on the other hand– filed herewith
|
|
23.01
|
Consent
of LaRoche Petroleum Consultants, Ltd. - filed herewith
|
|
31.01
|
Sarbanes
Oxley Section 302 Certifications - filed herewith
|
|
32.01
|
Sarbanes
Oxley Section 906 Certifications - filed herewith
|
|
99.01
|
Our
2004 Consultant Compensation Plan (filed as Exhibit 4.1 to our
Registration Statement on Form S-8 (SEC File No. 333-114686) filed April
21, 2004.
|
|
99.02
|
Our
2005 Director Stock Plan (filed as Exhibit 4.2 to our Registration
Statement on Form S-8 (SEC File No. 333-124890) filed May 13,
2005.
|
|
99.03
|
Our
2007 Equity Incentive Plan (filed as Exhibit 4.2 to our Registration
Statement on Form S-8 (SEC File No. 333-146992) filed October 29,
2007.
|
ITEM
14. PR
INCIP
AL ACCOUNTANT FEES AND SERVICES.
During
2007 and 2006, the aggregate fees that we paid to Malone & Bailey, PC, our
independent auditors, for professional services were as follows:
|
|
|
Year
Ended December 31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Audit
Fees (1)
|
|
$
|
136,032
|
|
|
$
|
115,485
|
|
|
Audit-Related
Fees
|
|
|
33,194
|
(2)
|
|
|
41,681
|
(3)
|
|
Tax
Fees (4)
|
|
|
23,518
|
|
|
|
6,580
|
|
|
All
Other Fees
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
(1)
|
Fees for audit services include
fees associated with the annual audit and the review of our quarterly
reports on Form 10-QSB.
|
|
|
(2)
|
Fees
in connection with Crusader transaction.
|
|
|
(3)
|
Fees for the audits in connection
with the acquisition of EBS Oil and Gas Partners Production Company, L.P.
and EBS Oil and Gas Partners Operating Company,
L.P.
|
|
|
(4)
|
Consist primarily of professional
services rendered for tax compliance, tax advice and tax
planning.
|
Audit
Committee Pre-Approval of Audit and Permissible
Non-Audit
Services of Independent Registered Public Accounting
Firm.
The Audit
Committee pre-approves the engagement of Malone & Bailey, PC for all audit
and permissible non-audit services. The Audit Committee annually reviews the
audit and permissible non-audit services performed by Malone & Bailey, PC,
and reviews and approves the fees charged by Malone & Bailey, PC. The Audit
Committee has considered the role of Malone & Bailey, PC in providing tax
and audit services and other permissible non-audit services to us and has
concluded that the provision of such services was compatible with the
maintenance of Malone & Bailey, PC’s independence in the conduct of its
auditing functions.
REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM
To The
Board of Directors
Westside
Energy Corporation
Dallas,
Texas
We have
audited the accompanying consolidated balance sheets of Westside Energy
Corporation, (“Westside”) as of December 31, 2007 and 2006 and the related
consolidated statements of operations, changes in stockholders’ equity and cash
flows for the two years then ended. These consolidated financial statements are
the responsibility of Westside’s management. Our responsibility is to express an
opinion on these consolidated financial statements based on our
audits.
We
conducted our audits in accordance with standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the
consolidated financial statements are free of material misstatements. Westside
is not required to have, nor were we engaged to perform, an audit of its
internal control over financial reporting. Our audit included consideration of
internal control over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not for the purpose of
expressing an opinion on the effectiveness of Westside’s internal control over
financial reporting. Accordingly, we express no such opinion. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the consolidated financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well
as evaluating the overall consolidated financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
In our
opinion, the consolidated financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Westside as of
December 31, 2007 and 2006 and the consolidated results of its operations and
its cash flows for the two years then ended in conformity with accounting
principles generally accepted in the United States of America.
MALONE
& BAILEY, PC
www.malone-bailey.com
Houston,
Texas
March 31,
2008
|
Westside
Energy Corporation
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
December
31,
2007
|
|
|
December
31,
2006
|
|
|
ASSETS
|
|
|
|
|
|
|
|
Current
assets
|
|
|
|
|
|
|
|
Cash
|
|
$
|
6,840,115
|
|
|
$
|
5,003,803
|
|
|
Certificates
of deposit and escrow account
|
|
|
27,887
|
|
|
|
27,887
|
|
|
Marketable
securities
|
|
|
-
|
|
|
|
425,000
|
|
|
Accounts
receivable net of allowance for doubtful accounts of $277,000 and
$0
|
|
|
3,693,250
|
|
|
|
5,189,504
|
|
|
Derivative
asset
|
|
|
-
|
|
|
|
169,885
|
|
|
Prepaid
assets
|
|
|
22,605
|
|
|
|
122,914
|
|
|
Total
current assets
|
|
|
10,583,857
|
|
|
|
10,938,993
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas properties, using successful efforts accounting
|
|
|
|
|
|
|
|
|
|
Proved
properties
|
|
|
42,187,569
|
|
|
|
19,179,048
|
|
|
Unproved
properties
|
|
|
10,001,881
|
|
|
|
10,094,150
|
|
|
Accumulated
depreciation, depletion and amortization
|
|
|
(10,404,761
|
)
|
|
|
(6,124,140
|
)
|
|
Net
oil and gas properties
|
|
|
41,784,689
|
|
|
|
23,149,058
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
financing costs net of accumulated amortization of $117,122 and
$66,593
|
|
|
211,091
|
|
|
|
265,907
|
|
|
Property
and equipment, net of accumulated depreciation of $138,809 and
$92,656
|
|
|
104,169
|
|
|
|
150,322
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$
|
52,683,806
|
|
|
$
|
34,504,280
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS' EQUITY
|
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
|
|
|
|
|
|
|
|
Accounts
payable and accrued expenses
|
|
$
|
13,372,617
|
|
|
$
|
7,171,069
|
|
|
Derivative
liability
|
|
|
54,644
|
|
|
|
-
|
|
|
Short
term portion of debt
|
|
|
-
|
|
|
|
3,997,500
|
|
|
Total
current liabilities
|
|
|
13,427,261
|
|
|
|
11,168,569
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-current
liabilities
|
|
|
|
|
|
|
|
|
|
Asset
retirement obligation
|
|
|
87,122
|
|
|
|
153,487
|
|
|
Long
term portion of debt, net of unamortized discount of $174,848 and
$404,325
|
|
|
28,717,652
|
|
|
|
7,609,057
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES
|
|
|
42,232,035
|
|
|
|
18,931,113
|
|
|
|
|
|
|
|
|
|
|
|
|
STOCKHOLDERS'
EQUITY
|
|
|
|
|
|
|
|
|
Preferred
stock, $0.01 par value, 10,000,000 shares authorized,
0 shares
issued and outstanding
|
|
|
-
|
|
|
|
-
|
|
Common
stock, $0.01 par value, 50,000,000 shares authorized,
25,361,273
and 21,461,909 shares issued and outstanding
|
|
|
253,612
|
|
|
|
214,619
|
|
|
Additional
paid-in capital
|
|
|
45,343,018
|
|
|
|
34,501,241
|
|
|
Accumulated
other comprehensive income - unrealized gain (loss) on derivative
instruments
|
|
|
(54,644
|
)
|
|
|
169,885
|
|
|
Accumulated
deficit
|
|
|
(35,090,215
|
)
|
|
|
(19,312,578
|
)
|
|
Total
stockholders' equity
|
|
|
10,451,771
|
|
|
|
15,573,167
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND STOCKHOLDERS' EQUITY
|
|
$
|
52,683,806
|
|
|
$
|
34,504,280
|
|
|
|
|
|
|
|
|
|
|
|
|
See
accompanying notes to consolidated financial statements.
|
|
|
|
|
|
|
|
|
|
Westside
Energy Corporation
|
|
Consolidated
Statements of Operations
|
|
Years
Ended December 31, 2007 and 2006
|
|
|
|
2007
|
|
|
2006
|
|
|
Revenues
|
|
|
|
|
|
|
|
Oil
and gas sales
|
|
$
|
6,440,087
|
|
|
$
|
3,915,209
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
2,386,951
|
|
|
|
1,779,192
|
|
|
Exploration
|
|
|
2,107,222
|
|
|
|
-
|
|
|
General
and administrative
|
|
|
5,970,874
|
|
|
|
5,296,723
|
|
|
Depreciation,
depletion and amortization
|
|
|
4,338,743
|
|
|
|
5,710,295
|
|
|
Impairment
|
|
|
4,519,346
|
|
|
|
4,310,330
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Expenses
|
|
|
19,323,136
|
|
|
|
17,096,540
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss
from Operations
|
|
|
(12,883,049
|
)
|
|
|
(13,181,331
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense)
|
|
|
|
|
|
|
|
|
|
Interest
income
|
|
|
358,926
|
|
|
|
225,619
|
|
|
Interest
expense
|
|
|
(3,253,514
|
)
|
|
|
(956,200
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Total
Other Income (Expense)
|
|
|
(2,894,588
|
)
|
|
|
(730,581
|
)
|
|
|
|
|
|
|
|
|
|
|
|
NET
LOSS
|
|
$
|
(15,777,637
|
)
|
|
$
|
(13,911,912
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income:
|
|
|
|
|
|
|
|
|
|
Unrealized
gain (loss) on derivative instruments
|
|
|
(224,529
|
)
|
|
|
-
|
|
|
Total
Comprehensive Loss
|
|
$
|
(16,002,166
|
)
|
|
$
|
(13,911,912
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Basic
and diluted loss per common share
|
|
$
|
(0.71
|
)
|
|
$
|
(0.66
|
)
|
|
Weighted
average common shares outstanding
|
|
|
22,146,313
|
|
|
|
21,041,220
|
|
|
|
|
|
|
|
|
|
|
|
|
See
accompanying notes to consolidated financial statements.
|
|
|
|
|
|
|
Westside
Energy Corporation
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
Years
Ended December 31, 2007 and 2006
|
|
|
|
2007
|
|
|
2006
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
Net
loss
|
|
$
|
(15,777,637
|
)
|
|
$
|
(13,911,912
|
)
|
Adjustments
to reconcile net loss to net cash
used in operating
activities
|
|
|
|
|
|
|
|
|
|
Accretion
of asset retirement obligation
|
|
|
8,818
|
|
|
|
-
|
|
|
Amortization
of discount on notes payable
|
|
|
501,338
|
|
|
|
82,076
|
|
|
Stock
based compensation
|
|
|
693,969
|
|
|
|
764,985
|
|
|
Impairment
of oil & gas properties
|
|
|
4,519,346
|
|
|
|
4,310,330
|
|
|
Amortization
of deferred financing cost
|
|
|
383,029
|
|
|
|
66,593
|
|
|
Depreciation,
depletion and amortization
|
|
|
4,329,925
|
|
|
|
5,710,295
|
|
|
Changes
in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
1,496,254
|
|
|
|
2,439,095
|
|
|
Prepaid
expenses and other current assets
|
|
|
100,309
|
|
|
|
(553,330
|
)
|
|
Accounts
payable & accruals
|
|
|
6,201,548
|
|
|
|
(6,418,551
|
)
|
|
NET
CASH USED IN OPERATING ACTIVITIES
|
|
|
2,456,899
|
|
|
|
(7,510,419
|
)
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
Proceeds
from sale of marketable securities
|
|
|
425,000
|
|
|
|
625,000
|
|
|
Cash
acquired on acquistion of EBS
|
|
|
-
|
|
|
|
955,574
|
|
|
Advances
to EBS
|
|
|
-
|
|
|
|
(3,644,754
|
)
|
|
Purchase
of office equipment
|
|
|
-
|
|
|
|
(75,938
|
)
|
|
Capital
expenditures for oil and gas properties
|
|
|
(24,775,794
|
)
|
|
|
(13,306,243
|
)
|
|
Proceeds
from sale of properties
|
|
|
-
|
|
|
|
4,941,985
|
|
|
NET
CASH USED IN INVESTING ACTIVITIES
|
|
|
(24,350,794
|
)
|
|
|
(10,504,376
|
)
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
Proceeds
from exercise of warrants
|
|
|
176,804
|
|
|
|
813,750
|
|
|
Proceeds
from sale of common stock, net
|
|
|
6,999,997
|
|
|
|
10,226,456
|
|
|
Proceeds
from loan - related party, net of financing costs
|
|
|
28,564,287
|
|
|
|
-
|
|
|
Proceeds
from loan - unrelated party, net of financing costs
|
|
|
-
|
|
|
|
14,887,500
|
|
|
Payments
on note
|
|
|
(12,010,881
|
)
|
|
|
(3,513,519
|
)
|
|
NET
CASH PROVIDED BY FINANCING ACTIVITIES
|
|
|
23,730,207
|
|
|
|
22,414,187
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
CHANGE IN CASH
|
|
|
1,836,312
|
|
|
|
4,399,392
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
BALANCES
|
|
|
|
|
|
|
|
|
|
Beginning
of period
|
|
|
5,003,803
|
|
|
|
604,411
|
|
|
End
of period
|
|
$
|
6,840,115
|
|
|
$
|
5,003,803
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL
CASH FLOW DISCLOSURES
|
|
|
|
|
|
|
|
|
|
Cash
paid for interest
|
|
$
|
1,711,614
|
|
|
$
|
956,200
|
|
|
Income
taxes paid
|
|
$
|
-
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
NON
CASH DISCLOSURES
|
|
|
|
|
|
|
|
|
|
Discount
on note payable
|
|
$
|
271,861
|
|
|
$
|
182,000
|
|
|
Value
of common stock component of purchase price of oil & gas
properties
|
|
$
|
3,010,000
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
See
accompanying notes to consolidated financial statements.
|
|
|
|
|
|
|
|
|
Westside
Energy Corporation
Consolidated
Statements of Changes in Stockholders' Equity
Years
Ended December 31, 2006 and 2007
|
|
|
Common
Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
Comprehensive
|
|
|
|
|
|
|
|
Shares
|
|
|
Par
Value
|
|
|
Paid-in
Capital
|
|
|
|
|
|
Income
|
|
|
Total
|
|
|
Balance
at December 31, 2005
|
|
|
17,376,745
|
|
|
|
173,767
|
|
|
|
22,736,902
|
|
|
|
(5,400,666
|
)
|
|
|
-
|
|
|
|
17,510,003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock
issued for warrants exercised
|
|
|
357,500
|
|
|
|
3,575
|
|
|
|
810,175
|
|
|
|
-
|
|
|
|
-
|
|
|
|
813,750
|
|
|
Stock
issued for services
|
|
|
94,384
|
|
|
|
944
|
|
|
|
326,204
|
|
|
|
-
|
|
|
|
-
|
|
|
|
327,148
|
|
|
Shares
sold for cash
|
|
|
3,457,972
|
|
|
|
34,580
|
|
|
|
10,191,876
|
|
|
|
-
|
|
|
|
-
|
|
|
|
10,226,456
|
|
|
Deferred
compensation
|
|
|
175,308
|
|
|
|
1,753
|
|
|
|
(1,753
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
Amortization
of deferred compensation
|
|
|
-
|
|
|
|
-
|
|
|
|
437,837
|
|
|
|
-
|
|
|
|
-
|
|
|
|
437,837
|
|
|
Unrealized
gain on derivative instruments
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
169,885
|
|
|
|
169,885
|
|
|
Net
Loss
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(13,911,912
|
)
|
|
|
-
|
|
|
|
(13,911,912
|
)
|
|
Balance
at December 31, 2006
|
|
|
21,461,909
|
|
|
$
|
214,619
|
|
|
$
|
34,501,241
|
|
|
$
|
(19,312,578
|
)
|
|
$
|
169,885
|
|
|
$
|
15,573,167
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock
issued for warrants exercised
|
|
|
353,608
|
|
|
|
3,536
|
|
|
|
173,268
|
|
|
|
-
|
|
|
|
-
|
|
|
|
176,804
|
|
|
Stock
issued for services
|
|
|
185,616
|
|
|
|
1,856
|
|
|
|
692,113
|
|
|
|
-
|
|
|
|
-
|
|
|
|
693,969
|
|
|
Shares
sold for cash
|
|
|
2,456,140
|
|
|
|
24,561
|
|
|
|
6,975,436
|
|
|
|
-
|
|
|
|
-
|
|
|
|
6,999,997
|
|
|
Stock
issued in exchange for oil & gas assets
|
|
|
904,000
|
|
|
|
9,040
|
|
|
|
3,000,960
|
|
|
|
|
|
|
|
|
|
|
|
3,010,000
|
|
|
Deferred
compensation
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
Amortization
of deferred compensation
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
Unrealized
gain on derivative instruments
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(224,529
|
)
|
|
|
(224,529
|
)
|
|
Net
Loss
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(15,777,637
|
)
|
|
|
|
|
|
|
(15,777,637
|
)
|
|
Balance
at December 31, 2007
|
|
|
25,361,273
|
|
|
$
|
253,612
|
|
|
$
|
45,343,018
|
|
|
$
|
(35,090,215
|
)
|
|
$
|
(54,644
|
)
|
|
$
|
10,451,771
|
|
See notes
to consolidated financial statements.
WESTSIDE
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of
operations and organization
Westside
Energy Corporation ("Westside") (formerly EvenTemp Corporation) was incorporated
in Nevada on November 30, 1995. EvenTemp operated an auto accessory business.
This business ceased operating in August 1999. The name of the company was
changed to Westside Energy Corporation in March 2004.
Westside
is engaged primarily in the acquisition, exploration, development, production,
and sales of oil and natural gas. Westside sells its oil and gas products
primarily to domestic natural gas pipelines and crude oil
marketers.
Principles
of Consolidation
Westside’s
consolidated financial statements include the accounts of Westside and its
wholly and majority owned subsidiaries. All significant intercompany accounts
and transactions have been eliminated in consolidation. Westside’s
undivided interests in unincorporated oil and gas exploration and production
ventures are proportionately consolidated.
Reclassifications
We have
reclassified certain prior-year amounts to conform to the current year’s
presentation.
Use of estimates
The
preparation of these financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.
The most
critical estimate we make is the engineering estimate of proved oil and gas
reserves. This estimate affects the application of the successful
efforts method of accounting, the calculation of depreciation, depletion
and amortization of oil and gas properties and the estimate of any impairment of
our oil and gas properties. It also affects the estimated lives used to
determine asset retirement obligations. In addition, the estimates of proved oil
and gas reserves are the basis for the related standardized measure of
discounted future net cash flows.
Revenue
recognition
Oil and
gas revenues are recognized when production is sold to a purchaser at a fixed or
determinable price, when delivery has occurred and title has transferred..
Westside did not have a significant imbalance position in terms of natural gas
volumes or values at December 31, 2007. Westside would account for
any gas imbalances using the entitlement method.
Oil and
gas properties
Westside
uses the successful efforts method of accounting for oil and gas producing
activities. Costs to acquire mineral interests in oil and gas properties, to
drill and equip exploratory wells that find proved reserves, to drill and equip
development wells, and related asset retirement costs are capitalized. Costs to
drill exploratory wells that do not find proved reserves, geological and
geophysical costs, and costs of carrying and retaining unproved properties are
expensed.
Unproved
oil and gas properties that are individually significant are periodically
assessed for impairment of value, and a loss is recognized at the time of the
impairment by providing an impairment allowance. Capitalized development costs
and asset retirement costs of producing oil and gas properties, after
considering estimated residual salvage values, are depreciated and depleted by
the units-of-production method over total proved producing
reserves. Leasehold costs are depleted by the units-of-production
method over estimated total proved reserves. Support equipment and other
property and equipment are depreciated over their estimated useful
lives.
On the
sale or retirement of a complete unit of proved property, the cost and related
accumulated depreciation, depletion, and amortization are eliminated from the
property accounts, and any gain or loss is recognized in income. On the
retirement or sale of a partial unit of proved property, the cost is charged to
accumulated depreciation, depletion, and amortization with any resulting gain or
loss recognized in income.
On the
sale of an entire interest in an unproved property for cash or cash equivalent,
gain or loss on the sale is recognized, taking into consideration the amount of
any recorded impairment if the property had been assessed individually. If a
partial interest in an unproved property is sold, the amount received is treated
as a reduction of the cost of the interest retained.
Property
and equipment
Property
and equipment are valued at cost. Additions are capitalized and
depreciated. All fixed assets excluding purchased software licenses
are depreciated using the double-declining balance method basis over a seven
year life. Purchased software is amortized using the straight line method over a
three year life. Leasehold improvements to our corporate office space
are depreciated over the life of the lease. Maintenance and repairs
are charged to expense as incurred. Gains and losses on dispositions of
equipment are reflected in other income and expense.
Long-lived
assets
Long-lived
assets to be held and used or disposed of other than by sale are reviewed for
impairment whenever events or changes in circumstances indicate that the
carrying amount may not be recoverable. When required, impairment losses on
assets to be held and used or disposed of other than by sale are recognized
based on the fair value of the asset. Long-lived assets to be disposed of by
sale are reported at the lower of the asset's carrying amount or fair value less
cost to sell.
Seismic
costs
Management
considers 3-D seismic surveys over acreage with proved reserves assigned to be
development activities. For development projects, the Company uses its 3-D
seismic database to select drill sites, assess recompletion opportunities and
production issues, quantify reservoir size and determine probable extensions
and/or drainage areas for existing fields. Westside amortizes the cost of its
capitalized developmental 3-D seismic survey costs using the unit-of-production
method. Costs for 3-D seismic surveys over unproven acreage are defined as
related to exploration activities and are expensed in the period
incurred.
Cash and
cash equivalents
Cash and
cash equivalents include cash in banks and certificates of deposit which mature
within three months of the date of purchase.
Marketable
Securities
Westside
classifies its investments in marketable securities as available-for-sale in
accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and
Equity Securities.” Marketable securities are reported at estimated
fair value with unrealized gains and losses included in other comprehensive
income, net of applicable deferred income taxes. Any annual amortization or
accretion is recorded as a charge or credit to interest income. Realized gains
and losses on sales are recognized in net income on the specific identification
basis. The estimated fair values of investments are based on quoted market
prices or dealer quotes.
Accounts
Receivable
We record
trade accounts receivable at the amount we invoice our joint venture partners.
These accounts do not bear interest. The allowance for doubtful accounts is our
best estimate of the amount of probable credit losses in our accounts receivable
as of the balance sheet date. We determine the allowance based on the
creditworthiness of our customers and general economic conditions. Consequently,
an adverse change in those factors could affect our estimate of our allowance
for doubtful accounts. We review our allowance for doubtful accounts
quarterly. Balances more than 90 days past due are reviewed
individually for collectibility. We charge off account balances against the
allowance after we have exhausted all reasonable means of collection and
determined that the potential for recovery is remote. We do not have any
off-balance sheet credit exposure related to our customers. At
December 31, 2007 and 2006, Westside recorded $277,000 and 0, respectively, to
its allowance for doubtful accounts.
Debt
Issuance Costs
Debt
issuance costs are deferred and recognized, using the effective interest method,
over the expected term of the related debt.
Stock-based
compensation
On
January 1, 2006, Westside adopted SFAS No. 123(R), "Share Based Payment". SFAS
123(R) replaced SFAS No. 123 and supersedes APB Opinion No. 25. SFAS 123(R)
requires all share-based payments to employees, including grants of employee
stock
options, to be recognized in the financial statements based on their fair
values. The pro forma disclosures previously permitted under SFAS 123 are no
longer an alternative to financial statement recognition. Westside adopted SFAS
123(R) using the modified prospective method which requires the application of
the accounting standard as of January 1, 2006.
Prior to
2006, Westside began issuing common stock to employees as compensation. Westside
recorded as compensation expense the fair value of such shares as calculated
pursuant to Statement of Financial Accounting Standard No. 123, Accounting for
Stock- Based Compensation, recognized over the related service period. Westside
has not offered options under its stock based compensation plans.
Westside
accounts for stock−based compensation issued to non−employees in accordance with
the provisions of SFAS No. 123(R) and EITF No. 96−18, "Accounting for Equity
Investments That Are Issued to Non−Employees for Acquiring, or in Conjunction
with Selling Goods or Services". For expensing purposes, the value of common
stock issued to non−employees and consultants is determined based on the fair
value of the equity instruments issued and charged to expense for the nature of
the service for which the stock compensation is paid.
Income
taxes
Westside
recognizes deferred tax assets and liabilities based on differences between the
financial reporting and tax basis of assets and liabilities using the enacted
tax rates and laws that are expected to be in effect when the differences are
expected to be recovered. Westside provides a valuation allowance for deferred
tax assets for which it does not consider realization of such assets to be more
likely than not.
Loss per
share
Basic and
diluted net loss per share calculations are calculated on the basis of the
weighted average number of common shares outstanding during the year. The per
share amounts include the dilutive effect of common stock equivalents in years
with net income. Westside had losses in 2007 and 2006. Basic and diluted loss
per share is the same due to the absence of common stock equivalents as the
effect of our potential common stock equivalents would be
anti-dilutive.
Derivatives
All
derivative instruments are recorded on the balance sheet at their fair value.
Changes in the fair value of each derivative are recorded each period in current
earnings or other comprehensive income, depending on whether the derivative is
designated as part of a hedge transaction and, if it is, the type of hedge
transaction. To make this determination, management formally documents the
hedging relationship and its risk−management objective and strategy for
undertaking the hedge, the hedging instrument, the item, the nature of the risk
being hedged, how the hedging instrument's effectiveness in offsetting the
hedged risk will be assessed, and a description of the method of measuring
ineffectiveness. This process includes linking all derivatives that are
designated as cash−flow hedges to specific cash flows associated with assets and
liabilities on the balance sheet or to specific forecasted
transactions.
Westside
also formally assesses, both at the hedge's inception and on an ongoing basis,
whether the derivatives that are used in hedging transactions are highly
effective in offsetting cash flows of hedged items. A derivative that is highly
effective and that is designated and qualifies as a cash−flow hedge has its
changes in fair value recorded in other comprehensive income to the extent that
the derivative is effective as a hedge. Any other changes determined to be
ineffective do not qualify for cash−flow hedge accounting and are reported
currently in earnings.
Westside
discontinues cash−flow hedge accounting when it is determined that the
derivative is no longer effective in offsetting cash flows of the hedged item;
the derivative expires or is sold, terminated, or exercised; the derivative is
redesignated as a non−hedging instrument because it is unlikely that a
forecasted transaction will occur; or management determines that designation of
the derivative as a cash−flow hedge instrument is no longer appropriate. In
situations in which cash−flow hedge accounting is discontinued, Westside
continues to carry the derivative at its fair value on the balance sheet and
recognizes any subsequent changes in its fair value in earnings.
When the
criteria for cash−flow hedge accounting are not met, realized gains and losses
(i.e., cash settlements) are recorded in other income and expense in the
Statements of Operations. Similarly, changes in the fair value of the derivative
instruments are recorded as unrealized gains or losses in the Statements of
Operations. In contrast, cash settlements for derivative instruments that
qualify for hedge accounting are recorded as additions to or reductions of oil
and gas revenues while changes in fair value of cash flow hedges are recognized,
to the extent the hedge is effective, in other comprehensive income until the
hedged item is recognized in earnings.
New
accounting standards
Westside
does not expect the adoption of any recently issued accounting pronouncements to
have a significant impact on its results of operations, financial position or
cash flows.
NOTE 2 -
CONCENTRATION OF CREDIT RISK
At
December 31, 2007, Westside's cash in financial institutions exceeded the
federally insured deposits limit by $6,908,127.
NOTE 3 -
MARKETABLE SECURITIES
On
December 31, 2006, Westside owned $425,000 in corporate bonds with no unrealized
gains or losses and an estimated fair value of $425,000. Westside
sold this asset in the first quarter of 2007 and, therefore, owns no marketable
securities at December 31, 2007.
NOTE 4 –
ACQUISITION OF ADDITIONAL MINERAL INTERESTS FROM GULFTEX OPERATING, INC. AND TD
ENERGY SERVICES, INC.
On
September 25, 2007, Westside acquired from Gulftex Operating, Inc. and TD Energy
Services, Inc. ("Sellers”) various working interests in five producing wells
and on leases covering an aggregate of 1,400 gross acres in Denton,
Johnson, and Tarrant Counties, Texas. The aggregate consideration remitted by
Westside for these assets was valued at $5,010,000 comprising $2 million in cash
borrowed pursuant to the Knight Note (see Note 5) and 904,000 shares of our
common stock (see Note 12 below).
At
December 31, 2007, estimated proved reserves associated with this acquisition
are 7.6 BCF of natural gas (see Note 16, Supplemental Oil & Gas Information
(unaudited)).
NOTE 5 –
LONG TERM DEBT – RELATED PARTIES
Knight Note.
On
September 20, 2007, Westside entered into an unsecured Revolving Note with
Knight Energy Group II (“Knight”) (a Crusader Entity) with a maturity date of
September 1, 2008 (the “Knight Note”). On November 12, 2007, a Note
Modification Agreement was executed which extended the maturity of the Knight
Note to March 31, 2009. Under the terms of the Knight Note, Westside
may borrow up to $8 million at a floating interest rate equal to the thirty day
London Interbank Offer Rate (“LIBOR”) plus five percent per annum. At
December 31, 2007, the interest rate under the Knight Note was
9.86%. Interest is due and payable monthly, in arrears, on the first
day of each month beginning October 1, 2007. As a condition to a draw
against the Knight Note, Westside must provide a detailed Authorization for
Expenditures (an “AFE”). Upon the occurrence of an Event of Default,
as defined in the note agreement, Knight may, at its option, declare all
principal, together with accrued interest, immediately due and
payable.
Because
of the extended maturity of the Knight Note, the Knight Note has been classified
as long term in the accompanying balance sheet.
Senior Secured
Loan
. On March 23, 2007, Westside closed a $25 million senior
secured loan (the “Senior Secured Loan”) from four entities managed by
Wellington Management Company, LLP, the largest beneficial holder of our
outstanding common stock, to replace the credit facility previously provided by
GasRock Capital, LLC (“GasRock”). The Senior Secured Loan has a
maturity date of March 23, 2009.
As a
result of the payoff of the GasRock credit facility using funds received from
the Senior Secured Loan, all previously deferred financing costs and original
issue discounts associated with the loan provided by GasRock of $670,232 were
recorded in the first quarter of 2007 as a component of interest
expense.
The
Senior Secured Loan was provided by four private investment funds managed by
Wellington Management Company, LLP, then and now the largest beneficial holder
of Westside’s outstanding common stock. The Senior Secured Loan:
|
|
·
|
provided
$25 million in funds, which were advanced in their entirety upon
completion of the Senior Secured Loan;
|
|
|
·
|
is
secured by a first lien on all of the oil and gas properties comprising
Westside’s Southeast and Southwest Programs (as defined in the loan
agreement);
|
|
|
·
|
grants
to the lenders the right to receive a lien in any and all of the proceeds
received upon the sale of a property comprising Westside’s North Program
(as defined in the loan agreement) or any subsequent property acquired
with such proceeds;
|
|
|
·
|
bears
annual interest at 10.0% (or, in the case of default, 12.0%)
annually;
|
|
|
·
|
grants
to the lenders a three percent (3.0%) overriding royalty interest
(proportionately reduced to Westside’s working interest) in all oil and
gas produced from the properties then comprising Westside’s Southeast and
Southwest Programs;
|
|
|
·
|
contains
limiting operating covenants;
|
|
|
·
|
contains
events of default arising from, among other things, failure to
timely repay principal and interest or comply with certain covenants or a
change in control; and
|
|
|
·
|
requires
the repayment of the outstanding balance of the loan in March 2009;
and
|
|
|
·
|
provides
for semiannual payment of interest either in cash, if Westside so elects,
or, if Westside does not elect to pay interest in cash, at lender’s
election to receive interest either in shares of Westside common stock
(“Conversion Option”) or by rolling the interest into the principal
balance of the loan. Should the lender elect the Conversion
Option the Senior Secured Lender would receive shares converted at the
greater of either $3.00 per share or the average closing price of our
common stock for the ten days ending one day prior to the applicable date
for payment of interest in payment of the interest. In
September 2007, Westside elected to pay interest of $1,260,273.98 in
cash. At December 31, 2007, Westside accrued interest expense
of $657,534 associated with this loan; and in March 2008, Westside elected
not to pay interest in cash. As a result of Westside’s
election, the lender elected to have six months of interest rolled into
the principal balance of the Senior Secured Loan. Westside
determined that the Conversion Option on this loan did not contain a
beneficial conversion feature under EITF 98-5 and EITF 00-27
.
|
Westside
recorded a discount of $271,861 based upon the estimated fair value of the
overriding royalty interest that was conveyed to the lender upon
closing. As of December 31, 2007, $97,013 of this discount had been
amortized as a component of interest expense. Westside incurred fees and other
costs directly associated with this loan agreement of $328,213. These
fees have been recorded as deferred financing costs. As of December 31, 2007,
$117,122 of these deferred financing costs had been amortized as a component of
interest expense. Both the discount and deferred financing costs are being
amortized over the expected term of the note using the effective interest
method.
In
connection with the loan represented by the Knight Note (the “Knight Loan”),
Westside and the lenders under the Senior Secured Loan entered into an amendment
to the Senior Secured Loan, effective September 20, 2007. The
amendment permitted the Knight Loan, but required that any amounts borrowed
pursuant to the Knight Loan be used only for (1) the acquisition of oil and gas
properties from Gulftex Operating, Inc., (2) the development of existing oil and
gas properties, and (3) the payment of interest becoming owed on either the
Senior Secured Loan or the Knight Loan.
Westside
analyzed these instruments for derivative accounting consideration under SFAS
133 and EITF 00−19 and determined that derivative accounting is not
applicable.
NOTE 6 −
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
On March
17, 2006 and February 22, 2007, Westside entered into fixed oil and natural gas
price swap agreements (“Swaps”) in order to provide a measure of stability to
Westside's cash flows due to volatile oil and natural gas prices and to manage
our exposure to commodity price risk.
Westside
evaluated the Swaps pursuant to the provisions of SFAS No. 133 “Accounting
for Derivative Instruments and Hedging Activities,” and determined that the
Swaps qualify for cash-flow hedge accounting treatment.
These
Swaps cover a portion of the Company’s oil and natural gas production through
December 31, 2008 and the details are summarized below:
|
Production
Period
|
|
Type
of Instrument
|
|
Total
Volume
|
|
Average
Fixed Price
|
|
|
Fair
Value
|
|
|
2008
|
|
Oil
Fixed Price Swap
|
|
2,000
bbls.
|
|
$
|
66.15
|
|
|
$
|
(54,764
|
)
|
|
2008
|
|
Gas
Fixed Price Swap
|
|
140,000
MMBtu
|
|
$
|
7.54
|
|
|
$
|
120
|
|
Management
has determined the swaps qualify for cash−flow hedge accounting treatment. As of
December 31, 2007, Westside recognized a derivative liability of $54,644 with
the change in fair value reflected in other comprehensive income.
NOTE 7 -
ASSET RETIREMENT OBLIGATIONS
As
Westside develops or purchases oil and gas wells, Westside incurs an obligation
to recognize a liability commensurate with its working interest share of the
future abandonment and reclamation costs of each well (“ARO”) and a
corresponding increase in the carrying value of each well (“ARC”) on the date
the liability is measured and recorded. Westside accounts for the ARO
and the associated ARC in accordance with SFAS 143 “Accounting for Asset
Retirement Obligations”. The amounts recognized are based upon
numerous estimates and assumptions, including future retirement costs, future
recoverable quantities of oil and gas, future inflation rates, and the credit
adjusted risk free interest rate. Salvage values are not recognized
in the measurement of the ARO and ARC but are included in the calculation of net
book value of oil & gas assets subject to depletion, depreciation, and
amortization under the successful efforts method of accounting.
Westside
evaluates its ARO each quarter and records changes in the ARO and ARC resulting
from the addition of wells and changes in estimates that affect the estimated
cash outflows associated with the abandonment of each well.
Westside
records amortization of the ARC and accretion of the ARO over
time. Amortization of the ARC commences, on a units-of-production
basis, when its associated well begins production. Accretion of the
ARO is calculated over the estimated productive lives of the oil & gas
assets with which the liability is associated.
|
|
|
2007
|
|
|
2006
|
|
|
Balance
at beginning of year
|
|
$
|
153,487
|
|
|
$
|
27,880
|
|
|
Revision
of Estimate
|
|
|
(142,278
|
)
|
|
|
|
|
|
Liabilities
incurred
|
|
|
92,096
|
|
|
|
122,855
|
|
|
Settlements
of liabilities
|
|
|
(25,000
|
)
|
|
|
|
|
|
Accretion
expense
|
|
|
8,818
|
|
|
|
2,752
|
|
|
Balance
at end of year
|
|
$
|
87,123
|
|
|
$
|
153,487
|
|
NOTE 8 -
COMMITMENTS AND CONTINGENCIES
Legal
Proceedings.
We are not now a party to any legal proceeding
requiring disclosure in accordance with the rules of the U.S. Securities and
Exchange Commission. In the future, we may become involved in various
legal proceedings from time to time, either as a plaintiff or as a defendant,
and either in or outside the normal course of business. We are not now in a
position to determine when (if ever) such a legal proceeding may arise. If we
ever become involved in a legal proceeding, our financial condition, operations,
or cash flows could be materially and adversely affected, depending on the facts
and circumstances relating to such proceeding.
Environmental Matters.
As an owner or lessee
and operator of oil and gas properties, we are subject to various federal, state
and local laws and regulations relating to discharge of materials into, and
protection of, the environment. These laws and regulations may, among other
things, impose liability on the lessee under an oil and gas lease for the
cost of pollution clean-up resulting from operations and subject the lessee to
liability for pollution damages. In some instances, we could be directed to
suspend or cease operations in the affected area. We maintain insurance
coverage, which we believe is customary in the industry, although we are
not fully insured against all environmental risks. We are not aware of any
environmental claims existing as of December 31, 2007, which have not been
provided for, covered by insurance or otherwise would have a material impact on
our financial position or results of operations. There can be no assurance,
however, that current regulatory requirements will not change, or past
non-compliance with environmental laws will not be discovered on our
properties.
Cash
Calls.
Westside is subject to cash calls related to its
various investments in oil and gas properties. The potential cash calls are in
the normal course of business for Westside's oil and gas interests. Westside
will require funds in excess of its net cash flows from operations to meet its
cash calls for its various interests in oil and gas properties to explore,
produce, develop, and eventually sell the underlying natural gas and oil
products.
Office Lease
Agreement.
On April 11, 2006, Westside entered into an Office
Lease Agreement with its current landlord. Westside accounts for this
Office Lease Agreement as an operating lease. The Office Lease
Agreement will expire on July 31, 2008. Because of the merger
pursuant to the Contribution Agreement described more fully in Note 12, Westside
does not plan to extend or renew this lease. At December 31, 2007,
Westside owes $57,114 in base rent under this lease and will pay it in equal
monthly installments of $8,159 through July 31, 2008.
Registration Rights
Agreement.
Pursuant to a private placement of securities, more
fully described in Note 12, Westside entered into a registration rights
agreement whereby we are obligated to file with the U.S. Securities and Exchange
Commission (the "SEC") a registration statement (the "Registration Statement")
as soon as reasonably practicable but in any event within 270 days after
November 9, 2007 (the "Closing Date") to permit the registered resale of the
shares for a period of two years following the date that the Registration
Statement is first declared effective by the SEC. The registration rights
agreement provides that if the Registration Statement is not declared effective
by the earlier of (i) 270 days after the Closing Date or (ii) the fifth (5th)
business day following the date on which Westside is notified by the SEC that
such registration statement will not be reviewed or is no longer subject to
further review and comments, Westside will be required to pay a penalty to each
investor an amount of cash equal to one percent (1%) of such investor's purchase
price for the shares, and an additional one percent (1%) for each additional
30-day period during which the Registration Statement is not declared
effective. The registration rights agreement further provides that if
Westside voluntarily suspends the effectiveness of the Registration Statement
for longer than certain stipulated periods of time or the Registration Statement
becomes otherwise unavailable, Westside will be required to pay a penalty to
each investor an amount equal to one percent (1%) of such investor's purchase
price for the shares for each additional 30-day period during which the
effectiveness of such registration statement is so
suspended. Westside believes it is unlikely that circumstances will
arise that would subject Westside to the payment of such penalties.
NOTE 9 -
INCOME TAXES
During
2007 and 2006, Westside incurred net losses and therefore, had no federal income
tax liability. The net deferred tax asset generated by the loss carry-forward
has been fully reserved. The cumulative net operating loss carry-forward is
approximately $52,867,345 at December 31, 2007 and will expire in the years
from 2019 to 2027. Should a change in control occur, utilization of
the net operating loss carry-forward could be limited under Section 382 of the
Internal Revenue Code.
At
December 31, 2007, the deferred tax assets consisted of the
following:
|
Deferred
tax assets:
|
|
|
|
|
Net
operating losses
|
|
$
|
17,974,897
|
|
|
Less:
valuation allowance
|
|
|
(17,974,897
|
)
|
|
Net
deferred tax asset
|
|
$
|
-
|
|
In June
2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation
(FIN) No. 48, Accounting for Uncertainty in Income Taxes – an interpretation of
FASB Statement No. 109. FIN 48 prescribes a threshold condition that a tax
position must meet for any of the benefit of the uncertain tax position to be
recognized in the financial statements. Guidance is also provided regarding
derecognition, classification, and disclosure of these uncertain tax positions.
FIN 48 is effective for fiscal years beginning after December 15,
2006.
Westside
adopted the provisions of FIN 48 on January 1, 2007. At the date of adoption, we
had approximately $24 million of unrecognized tax benefits related to
alternative minimum tax (AMT) associated with uncertain tax positions. At
December 31, 2007, the amount of unrecognized tax benefits related to AMT
associated with uncertain tax positions was approximately $53 million. These AMT
liabilities can be used to offset future regular tax liabilities. Westside’s
uncertain tax positions arise from prior net operating losses (NOL) incurred in
previous years.
Westside
files income tax returns in the U.S. federal jurisdiction, having no filing
requirements in state and local jurisdictions. The Internal Revenue Service
(IRS) has not examined the income tax returns; therefore, the Company has no
assurance that an examination would not result in changes to the accumulated
NOL’s. Any changes or adjustments in an examination should not result in a
material change to our financial position, results of operations, or cash
flow.
NOTE 10 -
IMPAIRMENT OF LONG-LIVED ASSETS
Pursuant
to FASB Statement No. 144, Accounting for the Impairment or Disposal of
Long-Lived Assets, impairment losses of $4,519,346 and $4,310,330 for 2007 and
2006, respectively, have been recognized in loss from continuing operations
before income taxes under the caption "Impairment". For proved oil and gas
properties, the impairment loss was determined by subtracting the net book value
from the discounted amount of the estimated future cash flows of the wells with
the excess of net book value over estimated discounted future cash flows
comprising the amount of the impairment. Costs associated with
unproved leases having expired during the year and expected to expire during the
next year are charged to impairment as of the end of each year.
NOTE 11 –
STOCK COMPENSATION LIABILITY.
Westside
has granted to three employees, pursuant to their employment agreements, grants
of our common stock subject to criteria associated with the performance of the
price of our common stock. This is a performance based program
subject to the provision of FAS 123(R) by which a liability has been established
based on the probability that our common stock will achieve certain
prices. Under this plan, shares eligible to be granted to these
employees are issuable, without restriction, upon a change of control of
Westside. These shares would be issuable upon closing of the merger
described further in Note 12. Details of this issuance are as
follows:
|
|
|
|
|
|
|
|
|
December
31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Value
of performance based shares to be issued at a change of
control
|
|
|
|
|
|
|
|
$
|
2,806,000
|
|
|
Liability
recorded
|
|
|
|
|
|
|
|
|
1,368,294
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liability
remaining to be recognized
|
|
|
|
|
|
|
|
$
|
1,437,706
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount
to be recognized per quarter as liability and expense in
2008
|
|
|
|
|
|
|
|
$
|
718,853
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assumptions:
|
|
|
|
|
|
|
|
|
|
|
|
1) Merger
will close on June 30, 2008
|
|
|
2) Description
of performance based shares under the plan that will vest upon
change
of control:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
#
Shares
|
|
|
Price
per Share at Grant Date
|
|
|
Value
of Grant
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
600,000
|
|
|
$
|
3.30
|
|
|
$
|
1,980,000
|
|
|
|
|
|
175,000
|
|
|
$
|
3.50
|
|
|
|
612,500
|
|
|
|
|
|
70,000
|
|
|
$
|
3.05
|
|
|
|
213,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
845,000
|
|
|
|
|
|
|
$
|
2,806,000
|
|
NOTE 12 -
COMMON STOCK
During
2007, Westside had the following equity transactions:
|
|
·
|
Warrants
to purchase 353,608 shares were exercised for aggregate proceeds to
Westside of $176,804.
|
|
|
·
|
198,949
shares of common stock valued at $510,357 were awarded for current and
future services to be earned evenly over the next three
years. Of these shares, 41,283 were awarded to directors,
117,666 were awarded to employees, and 40,000 were awarded to
consultants. The par value of these shares was recorded through
common stock and additional paid-in capital. As the shares are earned, the
value of the shares is recorded to expense and additional paid-in capital.
For the year ended December 31, 2006, $405,957.01 was earned and expensed.
Awards to consultants were expensed in accordance with EITF 96-18
“Accounting for Equity Instruments That Are Issued to Other Than Employees
for Acquiring, or in Conjunction with Selling, Goods or
Services.”
|
|
|
·
|
The
termination of the engagement of a contractor who had previously been
issued shares resulted in the cancellation of 13,333 shares previously
issued for future services.
|
|
|
·
|
904,000
shares of common stock were issued on October 2, 2007, to Sellers as the
Stock Consideration component, totaling $3,010,000 in market value, of the
purchase price for assets that Westside purchased pursuant to the Purchase
and Sale Agreement among Westside and Sellers dated September 25, 2007
(See Note 4 above).
|
|
|
·
|
A
private placement of an aggregate of 2,456,140 shares were sold for net
proceeds of $6,975,136. These shares were sold as follows: to
Spindrift Partners L.P., 576,857 shares; to Spindrift Investors (Bermuda),
L.P., 686,300 shares; and to Knight Energy
Group II, LLC (a Crusader entity) 1,192,983 shares. In
connection with this placement, Westside entered into a registration
rights agreement whereby it obligated itself to file with the U.S.
Securities and Exchange Commission (the "SEC") a registration statement
(the "Registration Statement") as soon as reasonably practicable but in
any event within 270 days after November 9, 2007 (the "Closing Date") to
permit the registered resale of the shares for a period of two years
following the date that the Registration Statement is first declared
effective by the SEC. The registration rights agreement provides
that if the Registration Statement is not declared effective by the
earlier of (i) 270 days after the Closing Date or (ii) the fifth (5th)
business day following the date on which Westside is notified by the SEC
that such registration statement will not be reviewed or is no longer
subject to further review and comments, Westside will be required to pay a
penalty to each investor an amount of cash equal to one percent (1%) of
such investor's purchase price for the shares, and an additional one
percent (1%) for each additional 30-day period during which the
Registration Statement is not declared effective. The registration
rights agreement further provides that if Westside voluntarily suspends
the effectiveness of the Registration Statement for longer than certain
stipulated periods of time or the Registration Statement becomes otherwise
unavailable, Westside will be required to pay a penalty to each investor
an amount equal to one percent (1%) of such investor's purchase price for
the shares for each additional 30-day period during which the
effectiveness of such registration statement is so
suspended,
|
During
2006, Westside had the following equity transactions:
|
|
·
|
Warrants
to purchase 357,500 shares were exercised for total proceeds to Westside
of $813,750
|
|
|
·
|
94,384 shares of common stock
were awarded for services valued at
$327,148.
|
|
|
·
|
175,308 common shares valued at
$609,129 were issued for future services. The par value of these shares
was recorded through common stock and additional paid-in capital. As the
shares are earned, the value of the shares is recorded to expense and
additional paid-in capital. For the year ended December 31, 2006, $437,837
was earned and expensed.
|
|
|
·
|
In a private placement, 3,278,000
shares were sold for net proceeds of $9,659,544. Additionally, two
employees purchased 179,972 shares for
$472,500.
|
On
December 31, 2007, we entered into a Contribution Agreement (the “Contribution
Agreement”) pursuant to which we agreed to a merger with the privately held
Crusader Energy Group (“Crusader”). The merger is subject to our
stockholders’ approval. If the merger is approved and completed, the
ultimate equity owners of Crusader will receive between 157.4 million and 171.7
million shares of our common stock, subject (if additional cash capital
contributions are made to Crusader) to the issuance of additional shares up to
approximately 14.3 million on the basis of one additional share for each three
additional dollars of capital contributed. After the completion of
the merger, we would have between 183.8 million and 198.1 million shares
outstanding, depending on the aggregate amount of any additional capital
contributions to Crusader and prior to the effectiveness of a planned
one-for-two reverse stock split of our common stock.
NOTE 13 -
WARRANTS
Westside
had no warrants issued or outstanding until the year ended December 31, 2004.
During 2004, Westside issued warrants attached to debt, stock purchases, and for
consulting services. All issuances were approved by the Board of Directors.
During 2007, no additional warrants were issued. A summary of changes in
outstanding warrants is as follows:
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
Warrants
|
|
|
Share
Price
|
|
|
|
|
|
|
|
|
|
|
Outstanding
at December 31, 2005
|
|
|
1,277,500
|
|
|
$
|
1.36
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes
during the year:
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
-
|
|
|
|
-
|
|
|
Exercised
|
|
|
(357,500
|
)
|
|
|
2.28
|
|
|
Forfeited
|
|
|
-
|
|
|
|
-
|
|
|
Outstanding
at December 31, 2006
|
|
|
920,000
|
|
|
$
|
0.99
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes
during the year:
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
-
|
|
|
|
--
|
|
|
Exercised
|
|
|
(353,608
|
)
|
|
|
0.50
|
|
|
Forfeited
|
|
|
--
|
|
|
|
--
|
|
|
Outstanding
at December 31, 2007
|
|
|
566,392
|
|
|
$
|
1.29
|
|
|
Excercisable
at December 31, 2007
|
|
|
566,392
|
|
|
$
|
1.29
|
|
NOTE 14 −
PURCHASE OF EBS OIL AND GAS PARTNERS PRODUCTION COMPANY, L.P.
On March
15, 2006, Westside acquired EBS Oil and Gas Partners Production Company, L.P.
and EBS Oil and Gas Partners Operating Company, L.P. (collectively
"EBS"). This acquisition is more fully described in our Annual Report
on Form 10KSB for the year ended December 31, 2006. The following 2006 unaudited
pro forma information assumes the acquisition of EBS occurred as of January 1,
2006. No pro forma results are provided for 2007 because the effects of the EBS
transaction are included for a full twelve months of operations in
2007. Pro forma results are not necessarily indicative of what
actually would have occurred had the acquisition been in effect for the period
presented below.
Year
Ended December 31, 2006:
|
|
|
As
Reported
|
|
|
Pro-
Forma
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$
|
34,504,280
|
|
|
$
|
34,504,280
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
3,915,209
|
|
|
$
|
4,584,021
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Loss
|
|
$
|
(13,911,912
|
)
|
|
$
|
(14,087,928
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Loss
Per Share
|
|
$
|
(0.66
|
)
|
|
$
|
(0.67
|
)
|
NOTE 15 –
SUBSEQUENT EVENTS
Additional
hedging positions
.
During
the first quarter of 2008, we entered into two additional hedging transactions
in the form of costless collars. Both of these collars cover natural
gas to be produced for a one-year period starting in March 2008 in the case of
the first of these collars and starting in April 2008 in the case of the second
of these collars. The first of these collars has a floor of $8.00 and
a cap of $10.35 per MMBTU, while the second of these collars has a floor of
$9.00 and a cap of $12.50 per MMBTU.
Issuance of restricted shares of our
common stock to related parties.
On November 9, 2007, one
hundred thousand (100,000) restricted shares each were awarded, effective
January 1, 2008, to certain of our directors. The value of the awards
on the effective date was $2.27 per share. Shares awarded to
Directors Glick, Raymond, and Williamson will vest in three tranches, the first
of which vested on January 1, 2008. The second tranche will vest on
January 1, 2009, and the third tranche will vest, after two additional years
have elapsed, on January 1, 2011. Restricted (unvested) shares will
not vest upon a change of control unless it occurs after June 30, 2008, in which
case all restricted shares awarded to these directors would
vest. Shares awarded to Director Spickelmier will vest in the same
manner except that the limitation as regards the June 30, 2008 date for
a change of control does not apply, and Director Spickelmier’s
restricted shares would vest upon a change of control occurring at any
time.
NOTE 16
-- SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
Capitalized
Costs
Capitalized
costs incurred in property acquisition, exploration, and development activities
as of December 31, 2007 are as follows:
|
Total
Capitalized
|
|
$
|
52,189,450
|
|
|
Less:
Accumulated depletion
|
|
|
(10,404,761)
|
|
|
Net
Capitalized
|
|
$
|
41,784,689
|
|
Costs
incurred for property acquisition, exploration, and development activities for
the year ended December 31, 2007 are as follows:
|
Acquisition
of properties
|
|
|
|
|
Proved
|
|
$
|
4,837,941
|
|
|
Unproved
|
|
|
172,059
|
|
|
Exploration
costs
|
|
|
--
|
|
|
Development
costs
|
|
|
22,284,382
|
|
|
Total
costs incurred for property acquisition, exploration, and development
activities
|
|
$
|
27,294,382
|
|
Results
of operations for oil and gas producing activities for the year ended December
31, 2007 are as follows:
|
Oil
& gas sales (exclusive of hedging)
|
|
$
|
6,234,517
|
|
|
Production
costs
|
|
|
(2,386,951)
|
|
|
Exploration
expenses
|
|
|
(2,107,222
)
|
|
|
Depreciation,
depletion and amortization
|
|
|
(4,282,897)
|
|
|
Impairment
|
|
|
(4,519,346)
|
|
|
|
|
|
(7,061,899)
|
|
|
Income
tax expense
|
|
|
-
|
|
|
Results
of operations for oil and gas producing activities (excluding corporate
overhead and financing costs)
|
|
$
|
(7,061,899)
|
|
Reserve
information
The
following estimates of proved and proved developed reserve quantities and
related standardized measure of discounted net cash flow are estimates only, and
do not purport to reflect realizable values or fair market values of the
Company's reserves. The Company emphasizes that reserve estimates are inherently
imprecise and that estimates of new discoveries are more imprecise than those of
producing oil and gas properties. Accordingly, these estimates are expected to
change as future information becomes available. All of the Company's reserves
are located in the United States.
Proved
reserves are estimated reserves of crude oil (including condensate and natural
gas liquids) and natural gas that geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions. Proved developed
reserves are those expected to be recovered through existing wells, equipment,
and operating methods.
The
standardized measure of discounted future net cash flows is computed by applying
year-end prices of oil and gas (with consideration of price changes only to the
extent provided by contractual arrangements) to the estimated future production
of proved oil and gas reserves, less the estimated future expenditures (based on
year-end costs) to be incurred in developing and producing the proved reserves,
less estimated future income tax expenses (based on year-end statutory tax
rates, with consideration of future tax rates already legislated) to be incurred
on pretax net cash flows less tax basis of the properties and available credits,
and assuming continuation of existing economic conditions. The estimated future
net cash flows are then discounted using a rate of 10 percent per year to
reflect the estimated timing of the future cash flows.
|
|
2007
|
|
2006
|
|
|
|
Oil
|
|
Gas
|
|
Oil
|
|
Gas
|
|
|
|
(MBbls)
|
|
(MMcf)
|
|
(MBbls)
|
|
(MMcf)
|
|
|
Total
proved reserves
|
|
|
|
|
|
|
|
|
|
Beginning
of year
|
149.615
|
|
|
5,835.035
|
|
85.206
|
|
|
1,191.699
|
|
|
Extensions
and discoveries
|
1,779
|
|
|
3,243,971
|
|
8.856
|
|
|
1,001.032
|
|
|
Revisions
of previous estimates
|
86,237
|
|
|
1,495,771
|
|
(33.740)
|
|
|
(133.747)
|
|
|
Purchases
of minerals in place
|
-
|
|
|
7,607.733
|
|
112.174
|
|
|
4,136.802
|
|
|
Production
|
(24.079)
|
|
|
(794.923)
|
|
(22.881)
|
|
|
(360.751)
|
|
|
End
of the year proved reserves
|
213.552
|
|
|
17,387.587
|
|
149.615
|
|
|
5,835.035
|
|
|
End
of year proved developed reserves
|
72.058
|
|
|
9,616.208
|
|
85.385
|
|
|
3,277.562
|
|
|
Standardized
Measure of Discounted Future
|
|
|
|
|
Net
Cash Flows at December 31, 2007
|
|
(000's)
|
|
|
Future
cash inflows
|
|
$
|
121,561
|
|
|
Future
production costs
|
|
|
(25,495)
|
|
|
Future
development costs
|
|
|
(22,006)
|
|
|
Future
income tax expenses, at 34%
|
|
|
(8,760)
|
|
|
Future
net cash flows
|
|
|
65,300
|
|
|
|
|
|
|
|
|
Less:
10% annual discount for estimated timing of cash flows
|
|
|
(36,727)
|
|
|
Standardized
measures of discounted future net cash flows relating to proved oil and
gas reserves
|
|
$
|
28,573
|
|
The
following reconciles the change in the standardized measure of discounted future
net cash flow during 2007.
|
|
|
(000's)
|
|
|
Beginning
of year
|
|
$
|
12,203
|
|
|
Sales
of oil and gas produced, net of production costs
|
|
|
(3,848
|
)
|
|
Net
changes in prices net of production costs
|
|
|
7,115
|
|
|
Purchases
of minerals
|
|
|
13,648
|
|
|
Extensions,
discoveries and improved recovery net of future production and development
costs
|
|
|
5,414
|
|
|
Net
changes in estimated future development costs
|
|
|
(10,225
|
)
|
|
Development
costs incurred during the year that reduced future development
costs
|
|
|
6,295
|
|
|
Revisions
of previous quantity estimates
|
|
|
9,763
|
|
|
Change
in production rates
|
|
|
(12,276
|
)
|
|
Change
in discount
|
|
|
1,690
|
|
|
Change
in income tax expense
|
|
|
(1,206
|
)
|
|
End
of year
|
|
$
|
28,573
|
|
APPENDIX
A
Glossary
of Certain Natural Gas and Oil Terms
The
following are abbreviations and definitions of certain terms commonly used in
the natural gas and oil industry and in this Annual Report.
Bbl.
One stock tank
barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other
liquid hydrocarbons.
Bcf/d.
One billion cubic
feet per day.
Bcfe.
One billion cubic
feet equivalent of natural gas, calculated by converting oil to equivalent Mcf
at a ratio of 6 Mcf to 1 Bbl of oil.
Boe.
Barrels of oil
equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel
of oil.
Bop/d.
Barrels of oil
per day.
Btu or British thermal
unit.
The quantity of heat required to raise the temperature of one pound
of water by one degree Fahrenheit.
Btu/cf.
The heat
content, expressed in Btu’s, of one cubic foot of natural gas.
Completion.
The
installation of permanent equipment for the production of natural gas or
oil.
Developed acreage.
The
number of acres that are allocated or assignable to producing wells or wells
capable of production.
Development well.
A well
drilled into a proved natural gas or oil reservoir to the depth of a
stratigraphic horizon known to be productive.
Dry hole.
A well found
to be incapable of producing hydrocarbons in sufficient quantities such that
proceeds from the sale of such production exceed production expenses and
taxes.
Exploitation.
The continued development of a known producing formation in
a previously discovered field. To make complete or maximize the ultimate
recovery of oil or natural gas from the field by work including development
wells, secondary recovery equipment or other suitable processes and
technology.
Exploration.
The search
for natural accumulations of natural gas and oil by any geological, geophysical
or other suitable means.
Exploratory well.
A well
drilled to find and produce natural gas or oil reserves not classified as
proved, to find a new reservoir in a field previously found to be productive of
natural gas or oil in another reservoir or to extend a known
reservoir.
Field.
An area
consisting of either a single reservoir or multiple reservoirs, all grouped on
or related to the same individual geological structural feature and/or
stratigraphic condition.
Fracturing.
The
technique of improving a well’s production or injection rates by pumping a
mixture of fluids into the formation and rupturing the rock, creating artificial
channels. As part of this technique, sand or other material may also be injected
into the formation to keep the channels open, so that fluids or gases may more
easily flow through the formation.
Gross acres.
The total
acres in which we own any amount of working interest.
Gross wells.
The total
number of producing wells in which we own any amount of working
interest.
Horizontal drilling.
A
drilling operation in which a portion of the well is drilled horizontally within
a productive or potentially productive formation. This operation usually yields
a well which has the ability to produce higher volumes than a vertical well
drilled in the same formation.
Injection well or
injector.
A well that is used to place liquids or gases into the
producing zone during secondary/tertiary recovery operations to assist in
maintaining reservoir pressure and enhancing recoveries from the
field.
Lease.
An instrument
that grants to another (the lessee) the exclusive right to enter to explore for,
drill for, produce, store and remove natural gas and oil on the mineral
interest, in consideration for which the lessor is entitled to certain rents and
royalties payable under the terms of the lease. Typically, the duration of the
lessee’s authorization is for a stated term of years and “for so long
thereafter” as minerals are producing.
MBbl.
One thousand barrels of oil or other liquid
hydrocarbons.
Mcf.
One thousand cubic
feet of natural gas at standard atmospheric conditions.
Mcf/d.
One Mcf per
day.
Mcfe.
One thousand cubic
feet equivalent of natural gas, calculated by converting oil to equivalent Mcfs,
at a ratio of 6 Mcf to 1 Bbl of oil.
MMBtu.
Million British
thermal units.
MMcf.
One million cubic
feet of natural gas at standard atmospheric conditions.
Net acres.
Gross acres
multiplied by Westside’s percentage working interest in the
acreage.
Net production.
Production that is owned by Westside less royalties and production due
others.
Net wells.
The sum of
all the complete and partial well ownership interests (i.e., if we own 25%
percent of the working interest in eight producing wells, the subtotal of this
interest to the total net producing well count would be two net producing
wells).
Operator.
The individual
or company responsible for the exploration, exploitation, development and
production of a natural gas or oil well or lease.
Overriding royalty
interest.
Ownership in a percentage of production or production revenues,
free of the cost of production, created by the lessee, company and/or working
interest owner and paid by the lessee, company and/or working interest owner out
of revenue from the well.
Pay zones.
A reservoir
or portion of a reservoir that contains economically producible natural gas and
oil reserves.
Permeability.
The
capacity of a geologic formation to allow water, natural gas or oil to pass
through it.
Plugging and
abandonment.
Process whereby a well that is no longer needed is filled
with concrete and
abandoned
Productive well.
A well
with the capacity to produce hydrocarbons in sufficient quantities such that
proceeds from the sale of the production exceed production expenses and
taxes.
Prospect.
A specific geographic area which, based on supporting geological, geophysical or
other data and preliminary economic analysis using reasonable anticipated prices
and costs, is deemed to have potential for the discovery of commercial
hydrocarbons.
Proved developed
reserves.
Reserves that can be expected to be recovered through existing
wells with existing equipment and operating methods.
Proved reserves.
The
estimated quantities of oil, natural gas and natural gas liquids that geological
and engineering data demonstrate with reasonable certainty to be commercially
recoverable in future years from known reservoirs under existing economic and
operating conditions.
Proved undeveloped reserves
(PUD).
Proved reserves that are expected to be recovered from new wells
on undrilled acreage or from existing wells where a relatively major expenditure
is required for recompletion.
Reservoir.
A porous and
permeable underground formation containing a natural accumulation of producible
natural gas and/or oil that is confined by impermeable rock or water barriers
and is separate from other reservoirs.
Royalty.
An interest in
an oil and natural gas lease that gives the owner of the interest the right to
receive a portion of the production from the leased acreage, or of the proceeds
of the sale thereof, but generally does not require the royalty owner to pay any
portion of the costs of drilling or operating the wells on the leased acreage.
Royalties may be either landowner’s royalties, which are reserved by the owner
of the leased acreage at the time the lease is granted, or overriding royalties,
which are usually reserved by an owner of the leasehold in connection with a
transfer to a subsequent owner.
Secondary recovery.
An
artificial method or process used to restore or increase production from a
reservoir after the primary production by the natural producing mechanism and
reservoir pressure has experienced partial depletion. Gas injection and
waterflooding are examples of this technique.
Three-dimensional
seismic.
The method by which a three-dimensional image of the earth’s
subsurface is created through the interpretation of reflected seismic data
collected over a surface grid. Three-dimensional seismic surveys allow for a
more detailed understanding of the subsurface than do conventional surveys and
contribute significantly to field appraisal, exploitation and
production.
Tcf.
One trillion cubic
feet of natural gas
Undeveloped acreage.
Lease acreage on which wells have not been drilled or completed to a point that
would permit the production of commercial quantities of natural gas and oil
regardless of whether such acreage contains proved reserves.
Working interest.
An
interest in a natural gas and oil lease that gives the owner of the interest the
right to drill for and produce natural gas and oil on the leased acreage and
requires the owner to pay a share of the costs of drilling and production
operations.
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, Westside Energy Corporation has duly caused this annual report on Form
10-KSB to be signed on its behalf by the undersigned, thereunto duly
authorized.
|
March
31, 2008
|
WESTSIDE
ENERGY CORPORATION
|
|
|
|
|
|
|
|
|
|
|
By:
|
/s/
Douglas G. Manner
|
|
|
|
Douglas
G. Manner,
|
|
|
Chief
Executive Officer
|
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the Registrant and in the
capacities and on the dates indicated.
|
Name
|
|
Title
|
|
Date
|
|
|
|
|
|
|
|
/s/
Douglas G. Manner
|
|
Director,
Chief Executive Officer
|
|
March
31, 2008
|
|
Douglas
G. Manner
|
|
(Principal
Executive Officer)
|
|
|
|
|
|
|
|
|
|
/s/
Keith D. Spickelmier
|
|
Director,
Chairman of the Board
|
|
March
31, 2008
|
|
Keith
D. Spickelmier
|
|
|
|
|
|
|
|
|
|
|
|
/s/
Craig S. Glick
|
|
Director,
|
|
March
31, 2008
|
|
Craig
S. Glick
|
|
|
|
|
|
|
|
|
|
|
|
/s/
John T. Raymond
|
|
Director,
|
|
March
31, 2008
|
|
John
T. Raymond
|
|
|
|
|
|
|
|
|
|
|
|
/s/
Herbert C. Williamson
|
|
Director,
|
|
March
31, 2008
|
|
Herbert
C. Williamson
|
|
|
|
|
|
|
|
|
|
|
|
/s/
Sean J. Austin
|
|
Vice
President and
|
|
March
31, 2008
|
|
Sean
J. Austin
|
|
Chief
Financial Officer
|
|
|
|
|
|
(Principal
Financial Officer & Principal Accounting Officer)
|
|
|
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