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Quest Resource 10-K 2007 Documents found in this filing:
Table of Contents
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Commission file number: 0-17371
Registrant’s Telephone Number:
405-488-1304
Securities Registered Pursuant to Section 12(b) of the
Exchange Act:
Securities Registered Pursuant to Section 12(g) of the
Exchange Act:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes o
No þ
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or 15(d) of the
Act. Yes o
No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
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 þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
(§229.405 of this chapter) is not contained herein, and
will not 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-K
or any amendment to this
Form 10-K.
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, or a non-accelerated
filer. See definition of “accelerated filer and large
accelerated filer” in
Rule 12b-2
of the Exchange Act. (Check one):
Large accelerated
filer o Accelerated
filer þ Non-accelerated
filer o
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Act). Yes o
No þ
The aggregate market value of the voting stock held by
non-affiliates computed by reference to the last reported sale
of the registrant’s common stock on June 30, 2006, the
last business day of the registrant’s most recently
completed second fiscal quarter, at $13.55 per share was
$267,070,066. This figure assumes that only the directors and
officers of the registrant, their spouses and controlled
corporations were affiliates.
There were 22,206,014 shares outstanding of the
registrant’s common stock as of March 6, 2007.
DOCUMENTS INCORPORATED BY REFERENCE
The definitive proxy statement relating to the issuer’s
2007 Annual Meeting of Stockholders is incorporated by reference
in Part III to the extent described therein.
Table of Contents
PART I
Quest Resource Corporation. Quest Resource
Corporation is a Nevada corporation and was incorporated on
July 12, 1982. Its principal executive offices are located
at 9520 N. May Avenue, Suite 300, Oklahoma City,
OK 73120 and its telephone number is
(405) 488-1304.
Quest Resource Corporation is referred to in this report as the
“Company,” “Quest,” “we,”
“us” and “our.” The Company is a holding
company that conducts its operations primarily through its
subsidiaries. Unless otherwise indicated, references to the
Company include the Company’s operating subsidiaries.
Quest Cherokee, LLC. Our principal operating
subsidiary is Quest Cherokee, LLC, a Delaware limited liability
company (“Quest Cherokee”), which owns all of our
natural gas and oil wells and natural gas and oil leases in the
Cherokee Basin in southeastern Kansas and northeastern Oklahoma.
Bluestem Pipeline, LLC. Our natural gas
gathering pipeline network is owned by Bluestem Pipeline, LLC, a
Delaware limited liability company (“Bluestem”).
Bluestem was a wholly-owned subsidiary of Quest Cherokee until
the formation and contribution of our midstream assets to Quest
Midstream Partners, L.P. on December 22, 2006.
Quest Cherokee Oilfield Service, LLC. Our
field equipment is owned by Quest Cherokee Oilfield Service,
LLC, a Delaware limited liability company (“QCOS”).
QCOS also employees all of our field level employees and first
line supervisors that work on our natural gas and oil wells.
QCOS is a wholly-owned subsidiary of Quest Cherokee.
Other Subsidiaries. Our remaining subsidiaries
are:
QES, QOG, PGPC and STP are wholly-owned by Quest. PGPC owns all
of the outstanding member interests of PSI and PSI is the sole
member of J-W Gas. Together these subsidiaries own all of the
membership interests in Quest Cherokee. Our executive officers
and administrative employees are employed by QES.
On December 13, 2006, we formed Quest Midstream to own and
operate our natural gas gathering pipeline system. On
December 22, 2006, we transferred Bluestem to Quest
Midstream in exchange for 4.9 million
class B subordinated units, 35,134 class A
subordinated units and a 2% general partner interest. Also on
December 22, 2006, Quest Midstream sold 4,864,866 common
units, representing an approximate 48.64% interest in Quest
Midstream, for $18.50 per common unit, or approximately
$90 million of gross proceeds, pursuant to a purchase
agreement dated December 22, 2006, to a group of
institutional investors led by Alerian Capital Management, LLC,
and co-led by Swank Capital, LLC.
Quest Midstream GP, the sole general partner of Quest Midstream,
was formed on December 13, 2006. Quest Midstream GP owns
200,000 General Partner Units representing a 2% general partner
interest in Quest Midstream. We own 850 Member Interests
representing an 85% ownership interest in Quest Midstream GP,
Alerian owns 75 Member Interests representing a 7.5%
ownership interest in Quest Midstream GP and Swank owns 75
Member Interests representing a 7.5% ownership interest in Quest
Midstream GP.
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Quest Midstream GP’s sole business activity is to act as
the general partner of Quest Midstream and employs approximately
46 personnel that perform activities primarily related to the
pipeline infrastructure.
See “— Recent Developments” for additional
information regarding our formation of Quest Midstream.
Change in Fiscal Year. We elected to change
our year-end from May 31 to December 31, effective
January 1, 2005. Accordingly, our financial statements
included in this report consist of the financial statements for
the fiscal year ended May 31, 2004, the seven-month
transition period ended December 31, 2004, the calendar
year ended December 31, 2005 and the calendar year ended
December 31, 2006.
A Glossary of Oil and Gas Terms is included in this report
beginning on page 21.
We are an independent energy company engaged in the exploration,
development and production of natural gas. Our operations are
currently focused on the development of coal bed methane or CBM
in a 15 county region in southeastern Kansas and northeastern
Oklahoma known as the Cherokee Basin. As of December 31,
2006, we had 198.0 Bcfe of net proved reserves with a
PV-10 value
of $268.1 million. Our reserves are approximately
99% CBM and 60.4% proved developed. We believe we are
the largest producer of natural gas in the Cherokee Basin with
an average net daily production of 33.8 mmcfe for the year ended
December 31, 2006. Our reserves are long-lived with a
reserve life index of 20.3 years.
As of December 31, 2006, we owned the development rights to
523,929 net CBM acres throughout the Cherokee Basin and had
developed approximately 46% of our acreage. We presently operate
approximately 1,650 producing gas and oil wells. Our undeveloped
acreage contains approximately 1,760 proved undeveloped CBM
drilling locations. Over 99% of the CBM wells that have been
drilled on our acreage to date have been successful. None of our
acreage or producing wells is associated with coal mining
operations.
In addition to our CBM reserves and acreage, we own and operate
through Quest Midstream, a gas gathering pipeline network of
approximately 1,600 miles that serves our acreage position.
Presently, this system has a maximum daily throughput of 70
mmcf/d and is operating at about 77% capacity. We transport 100%
of our production through our gas gathering pipeline network to
interstate pipeline delivery points. Approximately 10% of the
current volumes transported on our pipeline system are for third
parties. As of December 31, 2006, we had an inventory of
approximately 250 drilled CBM wells awaiting connection to our
gas gathering system. It is our intention to focus on the
development of CBM reserves that can be immediately served by
our gathering system. In addition, we plan to continue to expand
our gathering system through Quest Midstream to serve other
areas of the Cherokee Basin where we intend to acquire
additional CBM acreage for development.
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On June 9, 2006, we and Quest Cherokee entered into a
$75 million six-year Third Lien Term Loan Agreement among
us, Quest Cherokee, Guggenheim Corporate Funding, LLC
(“Guggenheim”), as administrative agent, and the
lenders party thereto that was fully funded at the closing. See
Note 3 to our consolidated financial statements included
elsewhere in this report for additional information regarding
our third lien term loan facility.
On December 13, 2006, we formed Quest Midstream to own and
operate our natural gas gathering pipeline system. On
December 22, 2006, Quest Midstream sold 4,864,866 common
units, representing an approximate 48.64% interest in Quest
Midstream, for $18.50 per common unit, or approximately
$90 million of gross proceeds, pursuant to a purchase
agreement dated December 22, 2006, to a group of
institutional investors led by Alerian, and co-led by Swank. The
investors consisted of Alerian Opportunity Partners IV, LP
(“Alerian”), Swank MLP Convergence Fund, LP
(“Swank MLP Fund”), Swank Investment Partners, LP
(“SIP”), The Cushing MLP Opportunity Fund I, LP
(“Cushing MLP Fund”), The Cushing GP Strategies Fund,
LP (“Cushing GP Fund”, together with Swank MLP Fund,
SIP and Cushing MLP Fund, “Swank”), Tortoise Capital
Resources Corporation (“Tortoise”), Huizenga
Opportunity Partners, LP (“Huizenga”) and HCM Energy
Holdings, LLC (“HCM” and together with Alerian, Swank,
Tortoise and Huizenga, collectively, the “Investors”).
In addition, investors that purchased more than $25 million
of limited partner interests in Quest Midstream (that is,
Alerian and Swank) were able to purchase an aggregate 15% of the
member interests of Quest Midstream GP, Quest Midstream’s
general partner, for a nominal amount of $150. Quest Midstream
GP owns 200,000 general partner units and all of the incentive
distribution rights in Quest Midstream and we own 35,134
class A subordinated units and 4,900,000 class B
subordinated units. Since we continue to own a majority of the
partner interests in Quest Midstream and 85% of the member
interests in Quest Midstream GP, the financial statements of
Quest Midstream are consolidated with our financial statements.
As part of these transactions, we contributed all of the member
interests in Bluestem, which owns our natural gas gathering
pipeline system, to Quest Midstream. As a result, Bluestem is
now a wholly-owned subsidiary of Quest Midstream.
The proceeds of the offering were used as
follows: (i) $40 million was used to repay the
outstanding indebtedness under our revolving credit facility,
(ii) approximately $5.2 million was used to repay
trade payables incurred in connection with the construction and
operation of Bluestem’s natural gas gathering pipeline
network, (iii) approximately $8 million was used to
pay fees and expenses related to these transactions, and
(iv) the remaining funds of approximately
$36.8 million were distributed to us and will be used for
future development and acquisition
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activities in the Cherokee Basin. Of this amount,
$15 million was initially to be retained by Quest Midstream
as temporary working capital until the partnership obtained its
own working capital facility on January 31, 2007, at which
time the $15 million was distributed to us.
See our
Form 8-K
filed December 29, 2006 for additional information
regarding the formation of Quest Midstream and the terms of the
transaction.
Investors’ Rights Agreement. In
connection with the formation of Quest Midstream, we, Quest
Midstream and Quest Midstream GP entered into an investors’
rights agreement dated as of December 22, 2006 with the
Investors. Pursuant to the terms of the investors’ rights
agreement, Alerian and Swank each received a separate and
independent right to designate one natural person to serve as a
member of Quest Midstream GP’s board of directors. We have
the right to designate the remaining four members of the board
of directors of Quest Midstream GP (two of whom must be
independent directors). Swank’s right to designate a member
of the board of directors terminates upon the completion by
Quest Midstream of an initial public offering. In addition, the
right to designate a member of Quest Midstream GP’s board
of directors terminates as to Alerian or Swank if it ceases to
own at least 5% of Quest Midstream’s common units (on a
fully diluted basis) that are not held by us and our affiliates.
Subject to certain exceptions set forth in the investors’
rights agreement, if Quest Midstream has not completed an
initial public offering by December 22, 2008, then until
such time as an initial public offering is completed by Quest
Midstream, the Investors, acting by majority vote, may require
Quest Midstream GP to effect a sale of either all of Quest
Midstream’s assets or partner interests. If the Investors
make such an election, Quest Midstream GP will have the right to
offer to purchase all of the Investors’ interests in Quest
Midstream. If Quest Midstream GP’s offer is not accepted,
Quest Midstream GP will be obligated to undertake to solicit
offers for all of the assets or partner interests of Quest
Midstream as promptly as commercially reasonable with a view to
maximizing the aggregate consideration to be received for such
sale. The offers must meet certain minimum requirements that are
contained in the investors’ rights agreement. If a
qualifying offer is accepted by a majority of the Investors, we
and the other Investors will be required to participate in the
sale. Subject to certain limitations, Quest Midstream GP will
have a right of first refusal to match any offer accepted by a
majority of the Investors.
If a change of control of us occurs, a majority of Investors
will have the right to cause Quest Midstream GP to affect a sale
of Quest Midstream following the same procedures described
above, if an initial public offering for Quest Midstream is not
completed within half of the number of days remaining between
the change of control date and December 22, 2008.
In connection with any such sale of the assets or partner
interests of Quest Midstream, the Investors will be entitled to
a return of their initial investment (plus a 10% premium) and
any unpaid distributions before any funds will be distributed to
us on account of our general partner and subordinated units. If
the sale is not completed within 180 days after the
Investors’ inform Quest Midstream GP that they desire to
exercise their right to require a sale of Quest Midstream, the
premium will increase by 750 basis points each quarter,
until it reaches a maximum of 40%.
Subject to certain exceptions, any issuances of additional
partner interests by Quest Midstream for less than 115% of the
price at which the common units were issued to the Investors
will require the consent of the representatives of Swank and
Alerian serving on the board of directors of Quest Midstream GP.
If we and our affiliates desire to dispose of all or
substantially all of our collective Quest Midstream partner
interests and our collective general partner member interests to
a non-affiliated third-party, then the Investors will have the
right to participate in such transaction. We also have the right
to require the Investors to participate in such a transaction if
certain conditions are satisfied.
If we desire to sell a majority of our member interests in Quest
Midstream GP, Alerian and Swank will have a right of first
refusal to acquire the member interests being transferred.
Except for Alerian’s right to designate a member to serve
on Quest Midstream GP’s board of directors, the
investors’ rights agreement terminates upon the completion
of an initial public offering of Quest Midstream, which results
in the common units of Quest Midstream being listed on the
Nasdaq Global Market or the New York Stock Exchange.
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Omnibus Agreement. In connection with
the transactions contemplated by the purchase agreement, we,
Quest Midstream, Quest Midstream GP and Bluestem entered into an
omnibus agreement dated as of December 22, 2006. The
omnibus agreement governs (i) the obligations of us and our
affiliates to refrain from engaging in certain business
opportunities that compete with Quest Midstream, (ii) our
obligations to indemnify Quest Midstream, Quest Midstream GP and
Bluestem against certain environmental and other liabilities
that occurred or existed prior to the closing date,
(iii) the obligation of Quest Midstream to reimburse us for
certain insurance, operating and general and administrative
expenses incurred on behalf of Quest Midstream (subject to
certain limitations), (iv) a right of first offer allowing
Quest Midstream to acquire certain of our assets in the event of
a sale or transfer of such assets, and (v) an option
allowing Quest Midstream to provide midstream services for any
acreage located outside the Cherokee Basin that we or any of our
affiliates may acquire in the future.
Midstream Services and Gas Dedication
Agreement. We and Bluestem entered into a
midstream services and gas dedication agreement on
December 22, 2006. Pursuant to the midstream services
agreement, Bluestem agreed to gather and provide certain
midstream services to us for all natural gas produced from wells
in a 15-county area in Kansas and Oklahoma known as the Cherokee
Basin that are connected to Bluestem’s gathering system.
The term of the midstream services agreement is ten years, with
two additional five-year periods. Under the midstream services
agreement, we will pay Bluestem $0.50 per thousand cubic
feet (“mcf”) of gas for gathering, dehydration and
treating services and $1.10 per mcf of gas for compression
services, subject to annual adjustment based on changes in
natural gas prices and the producers price index. Such fees are
subject to renegotiation in connection with each renewal term.
Bluestem has the option to connect all of the natural gas wells
that we develop in the Cherokee Basin to its gathering system.
In addition, Bluestem is required to connect to its gathering
system, at its expense, any new natural gas well(s) that we
complete in the Cherokee Basin if Bluestem would earn a
specified internal rate of return from those wells. We also
committed to drill a total of 750 new wells in the Cherokee
Basin by December 22, 2008.
First Amended and Restated Agreement of Limited
Partnership of Quest Midstream Partners,
L.P. In connection with the closing of the
purchase agreement, we and Quest Midstream GP entered into the
first amended and restated agreement of limited partnership of
Quest Midstream Partners, L.P., which sets forth our rights and
obligations with respect to Quest Midstream.
Under the partnership agreement, during the subordination
period, the common units in Quest Midstream have the right to
receive quarterly distributions of available cash from operating
surplus (each as defined in the partnership agreement) in an
amount equal to the minimum quarterly distribution of
$0.425 per common unit plus any arrearages in the payment
of the minimum quarterly distribution on the common units from
prior quarters, before any distributions of available cash from
operating surplus may be made on the subordinated units. No
arrearages will be paid on the subordinated units during the
subordination period.
The class A subordinated units will automatically convert
on a
one-for-one
basis to common units upon the completion by Quest Midstream of
an initial public offering. Generally, the subordination period
for the class B subordinated units will extend until the
first day of any quarter beginning after December 22, 2013
or, if an initial public offering by Quest Midstream has
occurred, the fifth anniversary of the closing of the initial
public offering that certain financial tests are met. Generally,
upon expiration of the subordination period for the class B
subordinated units; each outstanding class B subordinated
unit will convert into one common unit and will then participate
pro rata with the other common units in distributions of
available cash.
If the tests for ending the subordination period are satisfied
for any three consecutive four-quarter periods ending on or
after the last day of the quarter containing the third
anniversary of the initial public offering of Quest Midstream,
25% of the subordinated units will convert into an equal number
of common units. Similarly, if those tests are also satisfied
for any three consecutive four-quarter periods ending on or
after the last day of the quarter containing the fourth
anniversary of the initial public offering of Quest Midstream,
an additional 25% of the subordinated units will convert into an
equal number of common units. The second early conversion of
subordinated units may not occur, however, until at least one
year following the end of the period for the first early
conversion of subordinated units.
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The partnership agreement sets forth the levels of distributions
to be made to each of the common unit holders and Quest
Midstream GP of available cash from operating surplus for any
quarter during and after the subordination period. The
partnership agreement provides that Quest Midstream GP initially
will be entitled to 2% of all distributions that Quest Midstream
makes prior to its liquidation. Quest Midstream GP has the
right, but not the obligation, to contribute a proportionate
amount of capital to Quest Midstream to maintain its 2% general
partner interest if Quest Midstream issues additional units.
Quest Midstream GP’s 2% interest, and the percentage of
Quest Midstream’s cash distributions to which it is
entitled, will be proportionately reduced if Quest Midstream
issues additional units in the future and Quest Midstream GP
partner does not contribute a proportionate amount of capital to
Quest Midstream in order to maintain its 2% general partner
interest.
The incentive distribution rights in Quest Midstream represent
the right to receive an increasing percentage (13%, 23% and 48%)
of quarterly distributions of available cash from operating
surplus after the minimum quarterly distribution and certain
specified target distribution levels have been achieved. Quest
Midstream GP partner currently holds the incentive distribution
rights, but may transfer these rights separately from its
general partner interest, subject to restrictions in the
partnership agreement.
Quest Midstream GP, as the holder of our incentive distribution
rights, has the right under the partnership agreement to elect
to relinquish the right to receive incentive distribution
payments based on the initial cash target distribution levels
and to reset, at higher levels, the minimum quarterly
distribution amount and cash target distribution levels upon
which the incentive distribution payments to Quest Midstream GP
would be set. Such reset right may be exercised, without
approval of the unit holders or the conflicts committee of Quest
Midstream GP, at any time when there are no subordinated units
outstanding and Quest Midstream has made cash distributions with
respect to the incentive distribution rights at the highest
level for each of the prior four consecutive fiscal quarters.
In connection with the resetting of the minimum quarterly
distribution amount and the target distribution levels and the
corresponding relinquishment by Quest Midstream GP of incentive
distribution payments, Quest Midstream GP will be entitled to
receive a number of newly issued class C units based on a
formula that takes into account the “cash parity”
value of the average cash distributions related to the incentive
distribution rights received by Quest Midstream GP for the two
quarters prior to the reset event as compared to the average
cash distributions per common unit during this period.
Following a reset election by Quest Midstream GP, the minimum
quarterly distribution amount will be reset to an amount equal
to the average cash distribution amount per common unit for the
two fiscal quarters immediately preceding the reset
election (such amount is referred to as the “reset
minimum quarterly distribution”) and the target
distribution levels will be reset to be correspondingly higher
such that Quest Midstream would distribute all of its available
cash from operating surplus for each quarter as set forth in the
partnership agreement.
Quest Midstream GP may not be removed except with the vote of
two-thirds of all of the outstanding units (including those
owned by us and our affiliates).
Amended and Restated Limited Liability Company Agreement
of Quest Midstream GP, LLC. In connection
with the closing of the purchase agreement, we, Alerian and
Swank entered into the amended and restated limited liability
company agreement of Quest Midstream GP, which sets forth our
rights and obligations with respect to Quest Midstream GP.
Quest Midstream GP limited liability company agreement requires
all available cash (as defined in the agreement) to be
distributed each quarter pro rata among the members in
proportion to their member interests. Subject to certain
exceptions, if Quest Midstream GP issues additional member
interests, each member has a pre-emptive right to acquire
additional member interests in order to maintain its percentage
ownership in Quest Midstream GP.
If a member desires to transfer its member interests in Quest
Midstream GP, Quest Midstream GP and then we (in that order)
have a right of first refusal to acquire the member interests
being transferred.
If we desire to transfer more than 50% of the member interests,
then we have the option to require Alerian and Swank to
participate in the sale on the same terms (the drag-along
right). If we do not exercise our drag-along right, then Alerian
and Swank have the right to elect to participate in the transfer
on the same terms and conditions (the
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tag-along right). These rights are in addition to those
described above with respect to the investors’ rights
agreement.
In addition, on December 22, 2006, we entered into
amendments to our current credit facilities. Among other things,
the amendments permitted us to transfer the member interests in
Bluestem to Quest Midstream, released the security interests of
the lenders in the member interests and assets of Bluestem and
resulted in the pledge of our class A and class B
subordinated partner interests in Quest Midstream and our 85%
member interest in Quest Midstream GP as collateral for these
credit facilities. In addition, the prepayment premiums for the
Second Lien Term Loan and Third Lien Term Loan were amended. See
Note 3 to our consolidated financial statements included
elsewhere in this report for additional information regarding
the amendments to our credit facilities.
On January 31, 2007, Bluestem and Quest Midstream entered
into a $75 million five-year revolving credit facility. The
Credit Agreement is among Bluestem, as the borrower, Quest
Midstream, as a guarantor, Royal Bank of Canada
(“RBC”), as administrative agent and collateral agent,
and the lenders party thereto. The credit facility is secured by
all of the member interests in Bluestem and substantially all of
Bluestem’s assets. See our Form
8-K filing
dated February 7, 2007 for further information regarding
Quest Midstream’s credit facility.
Our goal is to create stockholder value by investing capital to
increase reserves, production and cash flow. We intend to
accomplish this goal by focusing on the following key strategies:
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The Cherokee Basin is located in southeastern Kansas and
northeastern Oklahoma. Geologically, it is situated between the
Forest City Basin to the north, the Arkoma Basin to the south,
the Ozark Dome to the east and the Nemaha Ridge to the west.
Structurally, the Cherokee Basin is separated from the Forest
City Basin by the Bourbon Arch. The Cherokee Basin is a mature
producing area with respect to conventional reservoirs such as
the Bartlesville sandstones and the Mississippian lime stones,
which were developed beginning in the early 1900s.
The Cherokee Basin is part of the Western Interior Coal Region
of the central United States. The coal seams we target for
development are Pennsylvanian (Desmoinesian-Cherokee Group) in
age and are found at depths of 300 to 1,400 feet. The
principal formations we target include the Mulky,
Weir-Pittsburgh and the Riverton. These coal seams are blanket
type deposits, which extend across large areas of the basin.
Each of these seams generally range
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from two to five feet thick. Additional minor coal seams such as
the Summit, Bevier, Fleming and Rowe are found at varying
locations throughout the basin. These seams range in thickness
from one to two feet. The coal seams found in the Cherokee Basin
are primarily high-volatile A and B bituminous grade with
excellent permeability and gas saturations ranging from 150 to
380 scf/ton.
We develop our CBM reserves in the Cherokee Basin on
160 acre spacing. Our wells generally reach total depth in
1.5 days and our average cost for 2006 to drill and
complete a well and to build the related pipeline infrastructure
was approximately $180,000. We estimate that for 2007, our
average cost for drilling and completing a well will be
approximately $135,000 and Quest Midstream’s average cost
for building the related pipeline infrastructure will be
approximately $60,000 per well. We perforate and frac the
multiple coal seams present in each well. Our typical Cherokee
Basin multi-seam CBM well has net reserves of 130 mmcf. Our
general production profile for a CBM well averages an initial
15-20 mcf/d
(net), steadily rising for the first 12 months while water
is pumped off and the formation pressure is lowered. A period of
relatively flat production of
55-60 mcf/d
(net) follows the initial de-watering period for a period of
approximately 12 months. After 24 months, production
begins to decline at an annual rate of
12-14%. The
standard economic life is about 14 years. Our completed
wells rely on very basic industry technology and are
mechanically unchallenging.
Our development activities in the Cherokee Basin also include an
active program to recomplete CBM wells that produce from a
single coal seam to wells that produce from multiple coal seams.
During the year ended December 31, 2006, we recompleted
approximately 146 wellbores in Kansas and an additional
5 wellbores in Oklahoma and we had an additional
150 wellbores awaiting recompletion to multi-seam
producers. The recompletion strategy is to add 4-5 additional
pay zones to each wellbore, in a two-stage process at an average
cost of approximately $20,000 per well. Adding new zones to
a well has a brief negative effect on production by first taking
the well offline to perform the work and then by introducing a
second de-watering phase of the newly completed formations.
However, in the long term, we believe the impact of the
multi-seam recompletions will be positive as a result of an
increase in the rate of production and the ultimate recoverable
reserves available per well.
Wells are equipped with small pumping units to facilitate the
de-watering of the producing coal seams. Generally, upon initial
production, a single coal seam will produce
50-60 bbls
of water per day. A multi-seam completion produces about 150
bbls of water per day. Eventually, water production subsides to
30-50 bbls
per day. Produced water is disposed through injection wells we
drill into the underlying Arbuckle formation. One disposal well
will generally handle the water produced from 25 producing wells.
Exploration &
Production Activities
As of December 31, 2006, we controlled approximately
542,000 gross acres. The petroleum engineering firm of
Cawley, Gillespie & Associates, Inc., of
Ft. Worth, Texas, estimated our proved oil and natural gas
reserves to be as follows as of December 31, 2006:
estimated gross natural gas proved reserves of 242.4 Bcf,
of which 198.0 Bcf is net to the Company, and estimated
proved oil reserves of 40,800 gross (32,272 net)
barrels. The present value of these proved reserve assets,
discounted at 10% of the future net cash flow from the net
natural gas and oil reserves, is $268.1 million, before the
effect of income taxes.
As of December 31, 2006, we were producing natural gas from
approximately 1,650 wells (gross). Our total daily natural
gas sales (including pipeline-earned volume) as of
December 31, 2006 were approximately 40.8 mcf/d net (54.4
mcf/d gross).
We have a significant amount of acreage available for
development. As of December 31, 2006, we had leases with
respect to approximately 283,000 net undeveloped acres. For
the year ended December 31, 2006, we drilled approximately
622 gross wells and connected 638 gross wells to our
pipeline systems. We intend to drill approximately
550 gross wells annually during 2007 and 2008. We have
identified approximately 1,760 proved undeveloped drilling
locations and many more probable and possible drilling
locations. Management believes that we have the necessary
expertise, manpower and equipment capabilities required to carry
out these development plans. Management believes that
significant additional value will be created if the drilling
program continues to be successful in creating new natural gas
wells that convert raw acreage into proven natural gas reserves.
However, there can be no assurance that we will have the funding
required to be able to drill and develop that number of wells
during such time frame or as to the number of new wells that
will be producing wells.
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Most of this development type of drilling is in areas of known
natural gas reserves that involve much lower risk than the
exploratory type of drilling that is required when searching for
new natural gas reserves. We have enjoyed a new well success
rate of over 99%.
The following table sets forth certain information regarding our
ownership of productive wells and total acreage, as of
December 31, 2006, 2005 and 2004. For purposes of this
table, productive wells are wells currently in production and
wells capable of production.
As of December 31, 2006, we had 241,634 net developed
acres and 282,922 net undeveloped acres.
During the year ended December 31, 2006, we drilled
622 gross (605.8 net) new wells on our properties, all
being natural gas wells. The wells drilled have been evaluated
and were included in the year-end reserve report. The oil well
count remains constant as we are focusing on adding natural gas
reserves. (See “— Summary of New and Abandoned
Well Activity”). During the year ended December 31,
2006, we continued to lease additional acreage in certain core
development areas of the Cherokee Basin.
The following table summarizes the reserve estimate and analysis
of net proved reserves of natural gas and oil as of
December 31, 2006, 2005 and 2004 and May 31, 2004, in
accordance with Securities and Exchange Commission
(“SEC”) guidelines. The data was prepared by the
petroleum engineering firm Cawley, Gillespie &
Associates, Inc. in Ft. Worth, Texas. The present value of
estimated future net revenues from these reserves was calculated
on a non-escalated price basis discounted at 10% per year.
During 2006, we filed estimates of our natural gas and oil
reserves for the year 2005 with the Energy Information
Administration of the U.S. Department of Energy on
Form EIA-23.
The data on
Form EIA-23
was presented on a different basis, and included 100% of the
natural gas and oil volumes from our operated properties only,
regardless of our net interest. The difference between the
natural gas and oil reserves reported on
Form EIA-23
and those reported in this report exceeds 5%.
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The Company’s total proved reserves increased from 134.5
bcfe as of December 31, 2005 to 198.0 bcfe as of
December 31, 2006.
There are numerous uncertainties inherent in estimating natural
gas and oil reserves and their values. The reserve data set
forth in this report is only an estimate. Reservoir engineering
is a subjective process of estimating underground accumulations
of natural gas and oil that cannot be measured in an exact
manner. The accuracy of any reserve estimate is a function of
the quality of available data and of engineering and geological
interpretation and judgment. Furthermore, estimates of reserves
are subject to revision based upon actual production, results of
future development and exploration activities, prevailing
natural gas and oil prices, operating costs and other factors,
and such revisions can be substantial. Accordingly, reserve
estimates often differ from the quantities of natural gas and
oil that are ultimately recovered and are highly dependent upon
the accuracy of the assumptions upon which they are based. The
future net cash flow and present value of future net cash flow
amounts are estimates based upon current prices at the time the
reports were prepared and do not take into account the effects
of our natural gas hedging program.
Our proved reserves will generally decline as they are produced,
except to the extent that we conduct revitalization activities,
or acquire properties containing proved reserves, or both. To
increase reserves and production, we intend to continue our
development drilling and re-completion programs, to identify and
produce previously overlooked or bypassed zones in shut-in
wells, and to a lesser extent, acquire additional properties or
undertake other replacement activities. Our current strategy is
to increase our reserve base, production and cash flow through
the development of our existing natural gas fields and subject
to available capital, through the selective acquisition of other
promising properties where we can utilize our existing
technology and infrastructure. We can give no assurance that our
planned development activities will result in significant
additional reserves or that we will have success in discovering
and producing reserves at economical exploration and development
costs. The drilling of new wells is a speculative activity and
the possibility always exists that newly drilled wells will be
non-productive or fail to produce enough revenue to be
commercially worthwhile.
The following tables set forth certain information regarding the
natural gas and oil properties owned by us through our
subsidiaries. The natural gas and oil production figures reflect
the net production attributable to our revenue interest and are
not indicative of the total volumes produced by the wells.
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Summary
of New and Abandoned Well Activity
For purposes of the table below, the number of wells drilled
refers to the number of wells completed at any time during the
period, regardless of when drilling was initiated. Most of the
wells expected to be drilled in the next year will be of the
development category and in the vicinity of our existing or
planned construction pipeline network. However, we will devote a
small part of our drilling effort into exploratory wells in an
attempt to discover new natural gas reserves, which is a
high-risk endeavor. Our drilling, re-completion, abandonment,
and acquisition activities for the periods indicated are shown
below:
The 638 gross new natural gas wells completed for the year
ended December 31, 2006 reflect an average activity level
of approximately 53 gross wells per month. We plan to drill
and complete an average of approximately 46 gross wells per
month for year 2007, subject to capital being available for such
expenditures.
During the period from December 31, 2006 through
March 6, 2007, we drilled 79 gross wells and connected
74 gross wells. As of March 6, 2007, we were drilling
11 gross wells and approximately 5 gross wells were in
the process of being completed.
Delivery
Commitments
We do not have long-term delivery commitments. We market our own
natural gas and more than 95% of the natural gas was sold to
ONEOK Energy Marketing and Trading Company during 2006. More
than 95% of our
12
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natural gas was sold to ONEOK Energy Marketing and Trading
Company in 2005 and in the seven month transition period ended
December 31, 2004. More than 90% of our natural gas was
sold to ONEOK Energy Marketing and Trading Company during the
fiscal year ended May 31, 2004. No other customer of the
Company accounted for more than 10% of the consolidated revenues
for the years ended December 31, 2006 and 2005, the
transition period ended December 31, 2004 or the fiscal
year ended May 31, 2004.
Our oil is currently being sold to Coffeyville Refining.
Previously, it had been sold to Plains Marketing, LP. We do not
have a long-term contract for our oil sales.
We seek to reduce our exposure to unfavorable changes in natural
gas prices, which are subject to significant and often volatile
fluctuation, through the use of fixed-price contracts. The
fixed-price contracts are comprised of energy swaps and collars.
These contracts allow us to predict with greater certainty the
effective natural gas prices to be received for hedged
production and benefit operating cash flows and earnings when
market prices are less than the fixed prices provided in the
contracts. However, we will not benefit from market prices that
are higher than the fixed prices in the contracts for hedged
production. Collar structures provide for participation in price
increases and decreases to the extent of the ceiling prices and
floors provided in those contracts.
The following table summarizes the estimated volumes, fixed
prices, fixed-price sales and fair value attributable to the
fixed-price contracts as of December 31, 2006. See
Note 15 — Derivatives, in notes to consolidated
financial statements of this
Form 10-K.
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The estimates of fair value of the fixed-price contracts are
computed based on the difference between the prices provided by
the fixed-price contracts and forward market prices as of the
specified date, as adjusted for basis. Forward market prices for
natural gas are dependent upon supply and demand factors in such
forward market and are subject to significant volatility. The
fair value estimates shown above are subject to change as
forward market prices and basis change. See
Note 14 — Financial Instruments, in notes to
consolidated financial statements of this
Form 10-K.
Some of our fixed price contracts are tied to commodity prices
on the New York Mercantile Exchange (“NYMEX”), that
is, we receive the fixed price amount stated in the contract and
pay to our counterparty the current market price for gas as
listed on the NYMEX. However, due to the geographic location of
our natural gas assets and the cost of transporting the natural
gas to another market, the amount that we receive when we
actually sell our natural gas is based on the Southern Star
Central TX/KS/OK (“Southern Star”) first of month
index, with a small portion being sold based on the daily price
on the Southern Star index. The difference between natural gas
prices on the NYMEX and the price actually received by the
Company is referred to as a basis differential. Typically, the
price for natural gas on the Southern Star first of the month
index is less than the price on the NYMEX due to the more
limited demand for natural gas on the Southern Star first of the
month index. Recently, the basis differential has been
increasingly volatile and has on occasion resulted in us
receiving a net price for our natural gas that is significantly
below the price stated in the fixed price contract.
Our approximately 1,600 mile gas gathering pipeline network
is owned by Bluestem Pipeline. Prior to December 22, 2006,
Bluestem was a wholly-owned subsidiary. As discussed in
“— Recent Developments”, on
December 22, 2006, we formed Quest Midstream and
contributed our ownership interest in Bluestem to Quest
Midstream in exchange for general and limited partner interests.
We own approximately 51% of the partnership interests in Quest
Midstream and through our 85% ownership interest in the general
partner of Quest Midstream we continue to control the day to day
operations of our gas gathering pipeline network.
Our natural gas gathering pipeline network is located in
southeastern Kansas and northeastern Oklahoma and provides a
market outlet for natural gas in a region of approximately
1,000 square miles in size and has connections to both
intrastate and interstate delivery pipelines. As of
December 31, 2006, this pipeline network included 15
natural gas compressors that are owned by Bluestem and 68 larger
compressors that are rented.
The pipelines gather all of the natural gas produced by us in
addition to some natural gas produced by other companies. The
pipeline network is a critical asset for our future growth
because natural gas gathering pipelines are a costly component
of the infrastructure required for natural gas production and
such pipelines are not easily constructed. Much of the
undeveloped acreage targeted by us for future development is
accessible to our existing pipeline network, which management
believes is a significant advantage.
We are continuing to expand our pipeline infrastructure through
the development of new pipelines and to a lesser extent, through
the acquisition of existing pipelines.
The following table sets forth the number of miles of pipeline
acquired or constructed during the periods indicated.
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The table below sets forth the natural gas volumes transported
on our pipeline network during the year ended December 31,
2006 and 2005; the seven-month transition period ended
December 31, 2004 and for the fiscal year ended
May 31, 2004.
The natural gas volumes for the fiscal year ended May 31,
2004 include the Devon asset acquisition beginning
December 22, 2003 and the Perkins/Willhite acquisition
beginning June 1, 2003. As of December 31, 2006, the
total daily capacity was approximately 70 mmcf and the total
utilization was approximately 54 mmcf or 77%.
Field operations conducted by our personnel include duties
performed by “pumpers” or employees whose primary
responsibility is to operate the wells and the pipelines. Other
field personnel are experienced and involved in the activities
of well servicing, pipeline maintenance, the development and
completion of new wells and associated infrastructure, new
pipeline construction and the construction of supporting
infrastructure for new wells (such as electric service, salt
water disposal facilities, and natural gas feeder lines). The
primary equipment categories owned by us are trucks, well
service rigs, stimulation assets and construction equipment. We
utilize third party contractors on an “as needed”
basis to supplement our field personnel.
We also provide, on an in-house basis, many of the services
required for the completion and maintenance of our CBM wells.
Internally sourcing these functions significantly reduces our
reliance on third-party contractors, which typically provide
these services. We believe this results in reduced delays in
executing our plan of development. Also we are able to realize
significant cost savings because we can avoid paying price
mark-ups and
also because we are able to purchase our own supplies at bulk
discounts.
We rely on third-party contractors to drill our wells. Once a
well is drilled, we run our own casing and do our own cementing
work. We also perform our own fracturing and stimulation work.
Finally, we complete our own well site construction. We have our
own fleet of 20 well service units that we use in the
process of completing our wells, and also to perform remedial
field operations required to maintain production from our
existing wells. We do rely on third party contractors to perform
gas gathering system construction activities.
By retaining operational control of our crucial income producing
assets, management believes that we are better able to control
costs and minimize downtime of these critical assets.
We do not currently provide a material amount of services to
unaffiliated companies other than transportation of certain
third party production volumes.
Various aspects of our operations are, or in the future may be,
regulated by agencies of the federal government.
Under the Natural Gas Act of 1938, the Federal Energy Regulatory
Commission, or the FERC, regulates various aspects of the
operations of any “natural gas company,” including the
transportation of natural gas, rates and charges, construction
of new facilities, extension or abandonment of services and
facilities, the acquisition and disposition of facilities,
reporting requirements, and similar matters. Section 1(b)
of the Natural Gas Act of 1938 exempts natural gas gathering
facilities from the jurisdiction of the FERC. We believe our gas
gathering system meets the traditional tests which the FERC has
used to establish a pipeline’s status as a gatherer under
section 1(b) of the Natural Gas Act and are therefore not
subject to FERC jurisdiction.
If we were determined to be a natural gas company, our
operations would become regulated under the Natural Gas Act. We
believe the expenses associated with seeking certificate
authority for construction, service and abandonment,
establishing rates and a tariff for our gas gathering
activities, and meeting the detailed regulatory
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accounting and reporting requirements would substantially
increase our operating costs and would adversely affect our
profitability.
None of our current activities are subject to such regulation by
the FERC.
Our pipeline operations are currently limited to the States of
Kansas and Oklahoma. State regulation of gathering facilities
generally includes various safety, environmental and, in some
circumstances, nondiscriminatory take requirements, and
compliant-based rate regulation. Bluestem is licensed as an
operator of a natural gas gathering system with the Kansas
Corporation Commission, or KCC, and is required to file periodic
information reports with the KCC. We are not required to be
licensed as an operator or to file reports in Oklahoma with the
Oklahoma Corporation Commission, or OCC.
On those portions of our gas gathering system that are open to
third party producers, the producers have the ability to file
complaints challenging our gathering rates, terms of services
and practice. Our fees, terms and practice must be just,
reasonable, not unjustly discriminatory and not duly
preferential. If the KCC or the OCC, as applicable, were to
determine that the rates charged to a complainant did not meet
this standard, the KCC or the OCC, as applicable, would have the
ability to adjust our rates with respect to the wells that were
the subject of the complaint. We are not aware of any instance
in which either the KCC or the OCC has made such a determination
in the past.
These regulatory burdens may affect profitability, and
management is unable to predict the future cost or impact of
complying with such regulations. We do not own any pipelines
that provide intrastate natural gas transportation, so state
regulation of pipeline transportation does not directly affect
our operations. As with the FERC regulation described above,
however, state regulation of pipeline transportation may
influence certain aspects of our business and the market price
for our products.
The price at which we buy and sell natural gas currently is not
subject to federal regulation and, for the most part, is not
subject to state regulation. Our sales of natural gas are
affected by the availability, terms and cost of pipeline
transportation. As noted above, the price and terms of access to
pipeline transportation are subject to extensive federal and
state regulation. The FERC is continually proposing and
implementing new rules and regulations affecting those segments
of the natural gas industry, most notably interstate natural gas
transmission companies that remain subject to the FERC’s
jurisdiction. These initiatives also may affect the intrastate
transportation of natural gas under certain circumstances. The
stated purpose of many of these regulatory changes is to promote
competition among the various sectors of the natural gas
industry, and these initiatives generally reflect more
light-handed regulation. We cannot predict the ultimate impact
of these regulatory changes to our natural gas marketing
operations, and we note that some of the FERC’s more recent
proposals may adversely affect the availability and reliability
of interruptible transportation service on interstate pipelines.
We do not believe that we will be affected by any such FERC
action materially differently than other natural gas marketers
with whom we compete.
In addition to existing laws and regulations, the possibility
exists that new legislation or regulations may be adopted which
would have a significant impact on our operations or our
customers’ ability to use gas and may require us or our
customers to change their operations significantly or incur
substantial costs. Additional proposals and proceedings that
might affect the gas industry are pending before Congress, FERC,
the Minerals Management Service, state commissions and the
courts. We cannot predict when or whether any such proposals may
become effective. In the past, the natural gas industry has been
heavily regulated. There is no assurance that the regulatory
approach currently pursued by various agencies will continue
indefinitely.
Failure to comply with these laws and regulations may result in
the assessment of administrative, civil
and/or
criminal penalties, the imposition of injunctive relief or both.
Moreover, changes in any of these laws and
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regulations could have a material adverse effect on our
business. In view of the many uncertainties with respect to
current and future laws and regulations, including their
applicability to us, we cannot predict the overall effect of
such laws and regulations on our future operations.
Management believes that our operations comply in all material
respects with applicable laws and regulations and that the
existence and enforcement of such laws and regulations have no
more restrictive effect on our method of operations than on
other similar companies in the energy industry. We have internal
procedures and policies to ensure that our operations are
conducted in substantial regulatory compliance.
The exploration for and production of natural gas and the
related operation of pipelines, plants and other facilities for
gathering, compressing, dehydrating or treating natural gas and
other products is subject to stringent and complex laws and
regulations pertaining to health, safety and the environment. As
an owner or operator of natural gas wells and related gathering
facilities, we must comply with these laws and regulations at
the federal, state and local levels. These laws and regulations
can restrict or impact our business activities in many ways,
such as:
Failure to comply with these laws and regulations may trigger a
variety of administrative, civil and criminal enforcement
measures, including the assessment of monetary penalties, the
imposition of remedial requirements, and the issuance of orders
enjoining future operations. Certain environmental statutes
impose strict, joint and several liability for costs required to
clean up and restore sites where hazardous substances have been
disposed of or otherwise released. Moreover, it is not uncommon
for neighboring landowners and other third parties to file
claims for personal injury and property damage allegedly caused
by the release of substances or other waste products into the
environment.
It is possible that additional environmental regulations will
place more restrictions and limitations on activities that may
affect our business, and thus there can be no assurance as to
the amount or timing of future expenditures for environmental
compliance or remediation. We try to anticipate future
regulatory requirements that might be imposed and plan
accordingly to remain in compliance with changing environmental
laws and regulations and to minimize the costs of such
compliance.
While it is not possible to quantify the costs of compliance
with all applicable federal and state environmental laws, those
costs have been and are expected to continue to be significant.
Any environmental costs are in addition to well closing costs;
property restoration costs; and other, significant, non-capital
environmental costs, including costs incurred to obtain and
maintain permits, to gather and submit required data to
regulatory authorities, to characterize and dispose of wastes
and effluents, and to maintain management operational practices
with regard to potential environmental liabilities. Compliance
with these federal and state environmental laws has
substantially increased the cost of gas production, but is, in
general, a cost common to all domestic gas producers.
At the present time, we do not believe that compliance with
federal, state or local environmental laws and regulations will
have a material adverse effect on our business, financial
position or results of operations. We cannot assure you, however
that future events, such as changes in existing laws, the
promulgation of new laws, or the development or discovery of new
facts or conditions, will not cause us to incur significant
costs. The following is a discussion of the material
environmental and safety laws and regulations that relate to the
midstream natural gas industry. We believe that we are in
substantial compliance with all of these environmental laws and
regulations.
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Our operations are subject to the federal Clean Air Act and
comparable state laws and regulations. These laws and
regulations regulate emissions of air pollutants from various
industrial sources and also impose various monitoring and
reporting requirements. Such laws and regulations may require
that we obtain pre-approval for the construction or modification
of certain projects or facilities expected to produce air
emissions or result in the increase of existing air emissions,
obtain and strictly comply with air permits containing various
emissions and operational limitations, or use specific emission
control technologies to limit emissions. Our failure to comply
with these requirements could subject us to monetary penalties,
injunctions, conditions or restrictions on operations, and
potentially criminal enforcement actions. Historically, air
pollution control has become more stringent over time. This
trend is expected to continue. The cost of technology and
systems to control air pollution to meet regulatory requirements
is significant today. These costs are expected to increase as
air pollution control requirements increase. We believe,
however, that our operations will not be materially adversely
affected by such requirements, and the requirements are not
expected to be any more burdensome to us than to any other
similarly situated companies.
Our operations generate wastes, including some hazardous wastes
that are subject to the federal Resource Conservation and
Recovery Act, or RCRA, and comparable state laws, which impose
detailed requirements for the handling, storage, treatment and
disposal of hazardous and solid waste. RCRA currently exempts
many natural gas gathering and field processing wastes from
classification as hazardous waste. Specifically, RCRA excludes
from the definition of hazardous waste produced waters and other
wastes associated with the exploration, development or
production of crude oil and natural gas. However, these oil and
gas exploration and production wastes may still be regulated
under state law or the less stringent requirements of the Solid
Waste Disposal Act. Moreover, ordinary industrial wastes such as
paint wastes, waste solvents, laboratory wastes and waste
compressor oils may be regulated as hazardous waste. The
transportation of natural gas in pipelines may also generate
some hazardous wastes that are subject to RCRA or comparable
state law requirements.
The Comprehensive Environmental Response, Compensation and
Liability Act of 1980, as amended, or CERCLA, also known as
“Superfund,” and comparable state laws impose
liability, without regard to fault or the legality of the
original conduct, on certain classes of persons responsible for
the release of hazardous substances into the environment.
Although natural gas is excluded from CERCLA’s definition
of “hazardous substance,” in the course of our
ordinary operations we generate wastes and materials that fall
within the definition of a “hazardous substance.”
Under CERCLA, we could be subject to joint and several liability
for the costs of cleaning up and restoring sites where hazardous
substances have been released, for damages to natural resources
and for the costs of certain health studies.
Our operations are subject to the Federal Water Pollution
Control Act of 1972, as amended, also known as the Clean Water
Act, and analogous state laws and regulations. These laws and
regulations impose detailed permit requirements and strict
controls regarding the discharge of pollutants in waste water
and in storm water, including the discharge of dredged or fill
material, into waters of the United States. The unpermitted
discharge of pollutants, including discharges resulting from a
spill or leak incident, is prohibited. Any unpermitted release
of pollutants from our pipelines or facilities could result in
fines or penalties as well as significant remedial obligations.
Our pipelines are subject to regulation by the
U.S. Department of Transportation, or the DOT, under the
Natural Gas Pipeline Safely Act of 1968, as amended, or the
NGPSA, pursuant to which the DOT has established requirements
relating to the design, installation, testing, construction,
operation, replacement and management of pipeline facilities.
The NGPSA covers the pipeline transportation of natural gas and
other gases and requires any
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entity that owns or operates pipeline facilities to comply with
the regulations under the NGPSA, to permit access to and allow
copying of records and to make certain reports and provide
information as required by the Secretary of Transportation. We
believe that our pipeline operations are in substantial
compliance with applicable NGPSA requirements; however, if
new or amended laws and regulations are enacted or existing laws
and regulations are reinterpreted, future compliance with the
NGPSA could result in increased costs.
We are subject to the requirements of the Occupational Safety
and Health Act, referred to as OSHA, and comparable state laws
and standards that regulate the protection of the health and
safety of workers. In addition, the OSHA hazard communication
standard requires that information be maintained about hazardous
materials used or produced in our operations and that this
information be provided to employees, federal, state and local
government authorities and citizens.
Hydrogen sulfide gas is a byproduct of sour gas treatment.
Exposure to unacceptable levels of hydrogen sulfide (known as
sour gas) is harmful to humans, and prolonged exposure can
result in death. We employ numerous safety precautions to ensure
the safety of our employees. There are various federal and state
environmental and safety requirements that apply to facilities
using or producing hydrogen sulfide gas. Notwithstanding
compliance with such requirements, common law causes of action
are available to persons damaged by exposure to hydrogen sulfide
gas.
We operate in the highly competitive areas of acquisition and
exploration of natural gas properties in which other competing
companies may have substantially larger financial resources,
operations, staffs and facilities. In seeking to acquire
desirable new properties for future exploration we face
competition from other natural gas and oil companies. Such
companies may be able to pay more for prospective natural gas
properties or prospects and to evaluate, bid for and purchase a
greater number of properties and prospects than our financial or
human resources permit.
Since a significant majority of our pipeline and service
operations presently support our exploration and development
operations, these aspects of our business do not experience any
significant competition.
At March 6, 2007, we had an experienced staff of 265 field
employees in offices located in Chanute and Howard, Kansas and
Lenapah, Oklahoma, and 47 pipeline operations employees. Also,
at the headquarters office in Oklahoma City, our staff consists
of 42 executive and administrative personnel. None of our
employees are covered by a collective bargaining agreement.
Management considers its relations with our employees to be
satisfactory.
The office space for the corporate headquarters for us and our
subsidiaries is leased and is located at 9520 N. May
Avenue, Suite 300, Oklahoma City, OK 73120.
We also own a building located at 211 West 14th Street
in Chanute, Kansas 66720 that is used as an administrative
office, an operations terminal and a repair facility.
An office building at 127 West Main in Chanute, Kansas is
owned and operated by us as a geological laboratory. We also
lease an operational office that is located east of Chanute,
Kansas.
Additional information about us can be found on our website at
www.qrcp.net. We also provide free of charge on our website our
filings with the SEC, including our annual reports, quarterly
reports, and current reports along with any amendments thereto,
as soon as reasonably practicable after we have electronically
filed such material with, or furnished it to, the SEC.
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The terms defined in this section are used throughout this
Form 10-K.
Bcf. Billion cubic feet of natural gas.
Bcfe. Billion cubic feet equivalent,
determined using the ratio of six mcf of natural gas to one bbl
of crude oil, condensate or natural gas liquids.
Btu or British Thermal Unit. The quantity of
heat required to raise the temperature of one pound of water by
one degree Fahrenheit.
CBM. Coal bed methane.
Cherokee Basin. As used in this
Form 10-K
a ten county region in southeastern Kansas and northeastern
Oklahoma.
Completion. The installation of permanent
equipment for the production of oil or natural gas, or in the
case of a dry hole, the reporting of abandonment to the
appropriate agency.
Developed acreage. The number of acres that
are allocated or assignable to productive wells or wells capable
of production.
Development well. A well drilled within the
proved boundaries of an oil or natural gas reservoir with the
intention of completing the 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. Ordinarily considered to be a
form of development within a known reservoir.
Exploratory well. A well drilled to find and
produce oil or gas reserves not classified as proved, to find a
new reservoir in a field previously found to be productive of
oil or gas in another reservoir or to extend a known reservoir.
Farm-in or farm-out. An agreement under which
the owner of a working interest in an oil or gas lease assigns
the working interest or a portion of the working interest to
another party who desires to drill on the leased acreage.
Generally, the assignee is required to drill one or more wells
in order to earn its interest in the acreage. The assignor
usually retains a royalty or reversionary interest in the lease.
The interest received by an assignee is a “farm-in”
while the interest transferred by the assignor is a
“farm-out.”
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.
Frac/fracturing. The method used to increase
the deliverability of a well by pumping a liquid or other
substance into a well under pressure to crack and prop open the
hydrocarbon formation.
Gathering system. Pipelines and other
equipment used to move natural gas from the wellhead to the
trunk or the main transmission lines of a pipeline system.
Gross acres or gross wells. The total acres or
wells, as the case may be, in which a working interest is owned.
Highly volatile bituminous coal. Bituminous
coal with a high concentration of methane gas.
Horizon or formation. The section of rock,
from which gas is expected to be produced in commercial
quantities.
mcf. Thousand cubic feet of natural gas.
mcfe. Thousand cubic feet equivalent,
determined using the ratio of six mcf of natural gas to one bbl
of crude oil, condensate or natural gas liquids.
MMBtu. Million British thermal units.
mmcf. Million cubic feet of natural gas.
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mmcfe. Million cubic feet equivalent,
determined using the ratio of six mcf of natural gas to one bbl
of crude oil, condensate or natural gas liquids.
Net acres or net wells. The sum of the
fractional working interests owned in gross acres or well, as
the case may be.
NYMEX. The New York Mercantile Exchange.
Permeability. The ease of movement of water
and/or gases
through a soil material.
Perforation. The making of holes in casing and
cement (if present) to allow formation fluids to enter the well
bore.
PV-10 or
present value of estimated future net
revenues. An estimate of the present value of the
estimated future net revenues from proved gas reserves at a date
indicated after deducting estimated production and ad valorem
taxes, future capital costs and operating expenses, but before
deducting any estimates of federal income taxes. The estimated
future net revenues are discounted at an annual rate of 10% in
accordance with the SEC’s practice, to determine their
“present value.” The present value is shown to
indicate the effect of time on the value of the revenue stream
and should not be construed as being the fair market value of
the properties. Estimates of future net revenues are made using
oil and natural gas prices and operating costs at the date
indicated and held constant for the life of the reserves.
Productive well. A well that is found to be
capable of producing hydrocarbons in sufficient quantities such
that proceeds from the sale of such production exceed production
expenses and taxes.
Proved developed non-producing
reserves. Proved developed reserves expected to
be recovered from zones behind casings in existing wells.
Proved developed reserves. Proved reserves
that can be expected to be recovered from existing wells with
existing equipment and operating methods.
Proved reserves. The estimated quantities of
crude oil, natural gas and natural gas liquids 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 undeveloped reserves or 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.
Reserve life index. This index is calculated
by dividing total proved reserves by the production from the
previous year to estimate the number of years of remaining
production.
Reservoir. A porous and permeable underground
formation containing a natural accumulation of producible oil
and/or gas
that is confined by impermeable rock or water barriers and is
individual and separate from other reservoirs.
scf. Standard cubic feet of natural gas.
Shut in. Stopping an oil or gas well from
producing.
Unconventional resource development. A
development in which the targeted reservoirs generally fall into
three categories: (1) tight sands, (2) coal beds, and
(3) gas shales. The reservoirs tend to cover large areas
and lack the readily apparent traps, seals and discrete
hydrocarbon-water boundaries that typically define conventional
reservoirs. These reservoirs generally require stimulation
treatments or other special recovery processes in order to
produce economic flow rate.
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 oil or gas
regardless of whether or not such acreage contains proved
reserves.
Working interest. The operating interest that
gives the owner the right to drill, produce and conduct
operating activities on the property and receive a share of
production.
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Risks
Related to the Company’s Business
The Company’s revenues, profitability and future growth and
the carrying value of its natural gas and oil properties depend
to a large degree on prevailing natural gas and oil prices. The
Company’s ability to maintain or increase its borrowing
capacity and to obtain additional capital on attractive terms
also substantially depends upon natural gas and oil prices.
Prices for natural gas and oil are subject to large fluctuations
in response to relatively minor changes in the supply and demand
for natural gas and oil, uncertainties within the market and a
variety of other factors in large part beyond the Company’s
control, such as:
A sharp decline in the price of natural gas and oil prices would
result in a commensurate reduction in the Company’s
revenues, income and cash flows from the production of natural
gas and oil and could have a material adverse effect on the
carrying value of the Company’s proved reserves and its
borrowing base. In the event prices fall substantially, the
Company may not be able to realize a profit from its production
and would operate at a loss, and even relatively modest drops in
prices can significantly affect the Company’s financial
results and impede its growth. In recent decades, there have
been periods of both worldwide overproduction and
underproduction of hydrocarbons and periods of both increased
and relaxed energy conservation efforts. Such conditions have
resulted in periods of excess supply of, and reduced demand for,
crude oil on a worldwide basis and for natural gas on a domestic
basis. These periods have been followed by periods of short
supply of, and increased demand for, crude oil and natural gas.
The excess or short supply of natural gas and crude oil has
placed pressures on prices and has resulted in dramatic price
fluctuations even during relatively short periods of seasonal
market demand. Lower natural gas and oil prices may not only
decrease the Company’s revenues on a per unit basis, but
also may reduce the amount of natural gas and oil that the
Company can produce economically. This may result in the Company
having to make substantial downward adjustments to its estimated
proved reserves. If this occurs or if the Company’s
estimates of development costs increase, production data factors
change or the Company’s exploration results deteriorate,
accounting rules may require the Company to write down, as a
non-cash charge to earnings, the carrying value of its natural
gas and oil properties for impairments. The Company is required
to perform impairment tests on its assets whenever events or
changes in circumstances lead to a reduction of the estimated
useful life or estimated future cash flows that would indicate
that the carry amount may not be recoverable or whenever
management’s plans change with respect to those assets. The
Company may incur impairment charges in the future, which could
have a material adverse effect on the Company’s results of
operations in the period taken. For the year ended
December 31, 2006, the Company recorded a provision for
impairment of its gas properties in the amount of
$30.7 million.
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This
Form 10-K
contains estimates of natural gas reserves, and the future net
cash flows attributable to those reserves, prepared by Cawley,
Gillespie & Associates, Inc., the Company’s
independent petroleum and geological engineers. There are
numerous uncertainties inherent in estimating quantities of
proved reserves and cash flows from such reserves, including
factors beyond the Company’s control and the control of
Cawley, Gillespie & Associates, Inc. Reserve
engineering is a subjective process of estimating underground
accumulations of natural gas and oil that cannot be measured in
an exact manner. The accuracy of an estimate of quantities of
reserves, or of cash flows attributable to these reserves, is a
function of the available data; assumptions regarding future
natural gas and oil prices; expenditures for future development
and exploitation activities; and engineering and geological
interpretation and judgment. Reserves and future cash flows may
also be subject to material downward or upward revisions based
upon production history, development and exploitation activities
and natural gas and oil prices. Actual future production,
revenue, taxes, development expenditures, operating expenses,
quantities of recoverable reserves and value of cash flows from
those reserves may vary significantly from the assumptions and
estimates in this
Form 10-K.
Any significant variance from these assumptions to actual
figures could greatly affect the Company’s estimates of
reserves, the economically recoverable quantities of natural gas
attributable to any particular group of properties, the
classification of reserves based on risk of recovery, and
estimates of the future net cash flows. In addition, reserve
engineers may make different estimates of reserves and cash
flows based on the same available data. The estimated quantities
of proved reserves and the discounted present value of future
net cash flows attributable to those reserves included in this
Form 10-K
were prepared by Cawley, Gillespie & Associates, Inc.
in accordance with the rules of the SEC, and are not intended to
represent the fair market value of such reserves.
The present value of future net cash flows from the
Company’s proved reserves is not necessarily the same as
the current market value of its estimated natural gas reserves.
The Company bases the estimated discounted future net cash flows
from its proved reserves on prices and costs. However, actual
future net cash flows from the Company’s natural gas and
oil properties also will be affected by factors such as:
The timing of both the Company’s production and its
incurrence of expenses in connection with the development and
production of natural gas properties will affect the timing of
actual future net cash flows from proved reserves, and thus
their actual present value. In addition, the 10% discount factor
the Company uses when calculating discounted future net cash
flows may not be the most appropriate discount factor based on
interest rates in effect from time to time and risks associated
with the Company or the natural gas and oil industry in general.
In addition, if natural gas prices decline, or our operating
expenses increase, by $0.10 per mcf, then the pre-tax
PV-10 of the
Company’s proved reserves as of December 31, 2006
would decrease from $268.1 million to $263.6 million.
The SEC permits natural gas companies, in their filings with the
SEC, to disclose only proved reserves that a company has
demonstrated by actual production or conclusive formation tests
to be economically and legally producible under existing
economic and operating conditions. The SEC’s guidelines
strictly prohibit the Company from including “probable
reserves” and “possible reserves” in filings with
the SEC. The Company also cautions you that the SEC views such
“probable” and “possible” reserve estimates
as inherently unreliable and these estimates may be seen as
misleading to investors unless the reader is an expert in the
natural gas industry. Unless you have such expertise, you should
not place undo reliance on these estimates. Potential investors
should also be aware that such “probable” and
“possible” reserve estimates will not be contained in
any “resale” or other registration
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statement filed by the Company that offers or sells shares on
behalf of purchasers of the Company’s common stock and may
have an impact on the valuation of the resale of the shares. The
Company undertakes no duty to update this information and does
not intend to update the information.
The rate of production from natural gas and oil properties
declines as reserves are depleted. As a result, the Company must
locate and develop or acquire new natural gas and oil reserves
to replace those being depleted by production. The Company must
do this even during periods of low natural gas and oil prices
when it is difficult to raise the capital necessary to finance
activities. The Company’s future natural gas reserves and
production and, therefore, the Company’s cash flow and
income are highly dependent on its success in efficiently
developing and exploiting its current reserves and economically
finding or acquiring additional recoverable reserves. The
Company may not be able to find and develop or acquire
additional reserves at an acceptable cost or have necessary
financing for these activities in the future.
The business of exploring for and, to a lesser extent,
developing and operating natural gas and oil properties involves
a high degree of business and financial risks, and thus a
substantial risk of investment loss that even a combination of
experience, knowledge and careful evaluation may not be able to
overcome. The cost of drilling, completing and operating wells
is often uncertain, and a number of factors can delay or prevent
drilling operations or production, including:
A productive well may become uneconomic in the event water or
other deleterious substances are encountered, which impair or
prevent the production of natural gas
and/or oil
from the well. In addition, production from any well may be
unmarketable if it is contaminated with water or other
deleterious substances. The Company may drill wells that are
unproductive or, although productive, do not produce natural gas
and/or oil
in economic quantities. Unsuccessful drilling activities could
result in higher costs without any corresponding revenues.
Acquisition and completion decisions generally are based on
subjective judgments and assumptions that are speculative. It is
impossible to predict with certainty the production potential of
a particular property or well. Furthermore, a successful
completion of a well does not ensure a profitable return on the
investment.
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The vast majority of the Company’s producing properties are
geographically concentrated in the Cherokee Basin of
southeastern Kansas and northeastern Oklahoma. As a result of
this concentration, the Company may be disproportionately
exposed to the impact of delays or interruptions of production
from these wells caused by significant governmental regulation,
transportation capacity constraints, curtailment of production,
natural disasters, adverse weather conditions or interruption of
transportation of natural gas produced from the wells in this
basin or other events which impact this area.
The
Company’s business involves many hazards and operational
risks, some of which may not be fully covered by insurance of
the Company or the operator of a property. If a significant
accident or event occurs that is not fully insured, the
Company’s operations and financial results could be
adversely affected.
The Company’s operations are subject to hazards and risks
inherent in producing and transporting natural gas and oil,
including:
Any of these or other similar occurrences could result in the
disruption of the Company’s operations, substantial repair
costs, personal injury or loss of human life, significant damage
to property, environmental pollution, impairment of the
Company’s operations and substantial revenue losses.
As protection against operating hazards, the Company maintains
insurance coverage against some, but not all, potential losses.
In addition, pollution and environmental risks generally are not
fully insurable. As a result of market conditions, premiums and
deductibles for certain insurance policies can increase
substantially, and in some instances, certain insurance may
become unavailable or available only for reduced amounts of
coverage. Additionally, the Company may elect not to obtain
insurance if it believes that the cost of available insurance is
excessive relative to the perceived risks presented. Losses
could, therefore, occur for uninsurable or uninsured risks or in
amounts in excess of existing insurance coverage. Moreover,
insurance may not be available in the future at commercially
reasonable costs and on commercially reasonable terms. Changes
in the insurance markets subsequent to the terrorist attacks on
September 11, 2001 and the hurricanes in 2005 have made it
more difficult for the Company to obtain certain types of
coverage. There can be no assurance that the Company will be
able to obtain the levels or types of insurance the Company
would otherwise have obtained prior to these market changes or
that the insurance coverage the Company does obtain will not
contain large deductibles or fail to cover certain hazards or
cover all potential losses. As a result, the Company may not be
able to renew its existing insurance policies or procure other
desirable insurance on commercially reasonable terms, if at all.
In addition, the Company believes any operators of its
properties or properties in which the Company may acquire an
interest will maintain similar insurance coverage. The
occurrence of an event that is not covered, or not fully
covered, by insurance could have a material adverse effect on
the Company’s business, financial condition and results of
operation.
The Company currently engages in hedging arrangements to reduce
its exposure to fluctuations in the prices of natural gas for a
significant portion of its current natural gas production. These
hedging arrangements expose the Company to risk of financial
loss in some circumstances, including when production is less
than expected; the
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counter-party to the hedging contract defaults on its contract
obligations; or there is a change in the expected differential
between the underlying price in the hedging agreement and the
actual prices received. In addition, these hedging arrangements
may limit the benefits the Company would otherwise receive from
increases in prices for natural gas. See Item 7.
“Management’s Discussion and Analysis of Financial
Condition Results of Operations — Quantitative and
Qualitative Disclosures About Market Risk” and
Items 1. and 2. “Description of Business and
Properties — Delivery Commitments — Hedging
Activities.”
The Company markets its own natural gas and more than 95% of its
natural gas was sold to ONEOK Energy Marketing and Trading
Company (“ONEOK”) during 2006. Tenaska was added as a
purchaser in December 2006 and may purchase 10% or more during
year 2007. In the event that ONEOK or Tenaska were to experience
financial difficulties or were to no longer purchase the
Company’s natural gas, the Company could, in the short
term, experience difficulty in its marketing of natural gas,
which could adversely affect its results of operations.
The Company constantly evaluates opportunities to acquire
additional natural gas and oil properties and frequently engages
in bidding and negotiation for these acquisitions. If successful
in this process, the Company may alter or increase its
capitalization through the issuance of additional debt or equity
securities, the sale of production payments or other measures.
Any change in capitalization affects the Company’s risk
profile. A change in capitalization, however, is not the only
way acquisitions affect the Company’s risk profile.
Acquisitions may alter the nature of the Company’s
business. This could occur when the character of acquired
properties is substantially different from the Company’s
existing properties in terms of operating or geologic
characteristics.
If an examination of the title history of a property that the
Company has purchased reveals that a natural gas or oil lease
has been purchased in error from a person who is not the owner
of the mineral interest desired, the Company’s interest
would be worthless. In such an instance, the amount paid for
such natural gas or oil lease or leases would be lost.
It is the Company’s practice, in acquiring natural gas and
oil leases, or undivided interests in natural gas and oil
leases, not to undergo the expense of retaining lawyers to
examine the title to the mineral interest to be placed under
lease or already placed under lease. Rather, the Company will
rely upon the judgment of natural gas and oil lease brokers or
landmen who perform the fieldwork in examining records in the
appropriate governmental office before attempting to acquire a
lease in a specific mineral interest.
Prior to the drilling of a natural gas or oil well, however, it
is the normal practice in the natural gas and oil industry for
the person or Company acting as the operator of the well to
obtain a preliminary title review of the spacing unit within
which the proposed natural gas or oil well is to be drilled to
ensure there are no obvious deficiencies in title to the well.
Frequently, as a result of such examinations, certain curative
work must be done to correct deficiencies in the marketability
of the title, and such curative work entails expense. The work
might include obtaining affidavits of heirship or causing an
estate to be administered. The Company’s failure to obtain
these rights may adversely impact its ability in the future to
increase production and reserves.
Several factors beyond the Company’s control may materially
adversely affect its ability to market the natural gas and oil
that it discovers. These factors include the proximity, capacity
and availability of natural gas and oil pipelines and processing
equipment, the level of domestic production and imports of
natural gas and oil, the demand for natural gas and oil by
utilities and other end users, the availability of alternative
fuel sources, the effect of inclement weather, state and federal
regulation of natural gas and oil marketing, market fluctuations
of prices, taxes, royalties, land tenure, allowable production
and environmental protection. The extent of these factors cannot
be
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accurately predicted, but any one or a combination of these
factors may result in the Company’s inability to sell its
natural gas at prices that would result in an adequate return on
its invested capital.
The Company may incur significant costs and liabilities as a
result of environmental, health and safety requirements
applicable to natural gas exploration and production activities.
These costs and liabilities could arise under a wide range of
federal, state and local environmental, health and safety laws
and regulations, including regulations and enforcement policies,
which have tended to become increasingly strict over time.
Failure to comply with these laws and regulations may result in
the assessment of administrative, civil and criminal penalties,
imposition of cleanup and site restoration costs and liens, and
to a lesser extent, issuance of injunctions to limit or cease
operations. In addition, claims for damages to persons or
property may result from environmental and other impacts of the
Company’s operations.
The Company is subject to regulation that restricts its ability
to discharge water produced as part of its coal bed methane gas
production operations. Coal beds frequently contain water that
must be removed in order for the gas to detach from the coal and
flow to the well bore, and the Company’s ability to remove
and dispose of sufficient quantities of water from the coal seam
will determine whether or not it can produce gas in commercial
quantities. The cost of water disposal, including the cost of
complying with regulations concerning water disposal, may
adversely affect the Company.
Strict, joint and several liability may be imposed under certain
environmental laws, which could cause the Company to become
liable for the conduct of others or for consequences of its own
actions that were in compliance with all applicable laws at the
time those actions were taken. New laws, regulations or
enforcement policies could be more stringent and impose
unforeseen liabilities or significantly increase compliance
costs. The Company does not carry insurance coverage against
many of these potential environmental liabilities. Consequently,
if the Company would be directly liable for damages resulting
from the occurrence of any such event, its financial condition
could be negatively impacted and, its ability to execute its
business plan could be impaired.
The Company’s operations are also subject to regulation at
the state and, in some cases, the county, municipal and local
governmental levels. Such regulations include requiring permits
for the construction, drilling and operation of wells,
maintaining bonding requirements in order to drill or operate
wells, regulating the surface use and requiring the restoration
of properties upon which wells are drilled, requiring the proper
plugging and abandonment of wells, and regulating the disposal
of fluids used and produced in connection with operations. The
Company’s operations are also subject to various state
conservation laws and regulations. These include regulations
that may affect the size of drilling and spacing units or
proration units, the density of wells which may be drilled, and
the mandatory unitization or pooling of gas properties. In
addition, state conservation regulations may establish the
allowable rates of production from gas wells, may prohibit or
regulate the venting or flaring of gas, and may impose certain
requirements regarding the ratability of gas production. State
regulation of gathering facilities generally includes various
safety, environmental and, in some circumstances,
nondiscriminatory and non-preferential purchase
and/or
transportation requirements, but does not generally entail rate
regulation. These regulatory burdens may adversely affect the
Company’s profitability.
The natural gas and oil industry is intensely competitive and
the Company competes with other companies from various regions
of the United States and may compete with foreign companies for
domestic sales, many of whom are larger and have greater
financial, technological, human and other resources. Many of
these companies not only explore for and produce crude oil and
natural gas but also carry on refining operations and market
petroleum and other products on a regional, national or
worldwide basis. Such companies may be able to pay more for
productive natural gas and oil properties and exploratory
prospects or define, evaluate, bid for and purchase a greater
number of properties and prospects than the Company’s
financial or human resources permit. In addition, such companies
may have a greater ability to continue exploration activities
during periods of low hydrocarbon
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market prices. The Company’s ability to acquire additional
properties and to discover reserves in the future will be
dependent upon the Company’s ability to evaluate and select
suitable properties and to consummate transactions in a highly
competitive environment. If the Company is unable to compete,
its operating results and financial position may be adversely
affected.
Because of the Company’s small size, growth in accordance
with its business plans, if achieved, will place a significant
strain on the Company’s financial, technical, operational
and management resources. As the Company expands its activities
and increases the number of projects it is evaluating or in
which it participates, there will be additional demands on the
Company’s financial, technical and management resources.
The failure to continue to upgrade the Company’s technical,
administrative, operating and financial control systems or the
occurrence of unexpected expansion difficulties, including the
recruitment and retention of experienced managers, geoscientists
and engineers, could have a material adverse effect on the
Company’s business, financial condition and results of
operations and the Company’s ability to timely execute its
business plan.
The success of the Company’s operations and activities is
dependent to a significant extent on the efforts and abilities
of the Company’s management. The loss of services of any of
the Company’s key managers could have a material adverse
effect on the Company’s business.
The demand for qualified and experienced field personnel to
drill wells and conduct field operations, geologists,
geophysicists, engineers and other professionals in the oil and
natural gas industry can fluctuate significantly, often in
correlation with oil and natural gas prices, causing periodic
shortages. Due to recent high natural gas and oil prices, the
Company has experienced shortages of drilling rigs and other
equipment, as demand for rigs and equipment has increased along
with the number of wells being drilled. Higher natural gas and
oil prices generally stimulate increased demand and result in
increased prices for drilling rigs, crews and associated
supplies, oilfield equipment and services and personnel in the
Company’s exploration and production operations. These
types of shortages or price increases could significantly
decrease the Company’s profit margin, cash flow and
operating results or restrict or delay its ability to drill
those wells and conduct those operations that it currently has
planned and budgeted.
The Company might acquire entire businesses in the future.
Potential risks involved in the acquisition of such businesses
include the inability to continue to identify business entities
for acquisition or the inability to make acquisitions on terms
that the Company considers economically acceptable. Furthermore,
there is intense competition for acquisition opportunities in
the Company’s industry. Competition for acquisitions may
increase the cost of, or cause the Company to refrain from,
completing acquisitions. The Company’s strategy of
completing acquisitions is dependent upon, among other things,
its ability to obtain debt and equity financing and, in some
cases, regulatory approvals. The Company’s ability to
pursue its growth strategy may be hindered if the Company is not
able to obtain such financing or regulatory approvals. The
Company’s ability to grow through acquisitions and manage
growth will require the Company to continue to invest in
operational, financial and management information systems and to
attract, retain, motivate and effectively manage the
Company’s employees. The inability to effectively manage
the integration of acquisitions could reduce the Company’s
focus on subsequent acquisitions and current operations, which,
in turn, could negatively impact the Company’s earnings and
growth. The Company’s financial position and results of
operations may fluctuate significantly from period to period,
based on whether or not significant acquisitions are completed
in particular periods.
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The Company makes, and will continue to make, substantial
capital expenditures for the exploration, acquisition and
production of natural gas and oil reserves. Historically, the
Company has financed these expenditures primarily with cash
generated by operations and proceeds from bank borrowings and
equity financings. If the Company’s revenues or borrowing
base decreases as a result of lower natural gas and oil prices,
operating difficulties or declines in reserves, the Company may
have limited ability to expend the capital necessary to
undertake or complete future drilling programs. Additional debt
or equity financing or cash generated by operations may not be
available to meet these requirements.
As of March 12, 2007 the Company had incurred
$225 million of indebtedness for borrowed money and
$10 million of indebtedness had been incurred by Quest
Midstream. The Company anticipates that it may in the future
incur additional debt for financing its growth. The
Company’s ability to borrow funds will depend upon a number
of factors, including the condition of the financial markets.
Under certain circumstances, the use of leverage may provide a
higher return to you on your investment, but will also create a
greater risk of loss to you than if the Company did not borrow.
The risk of loss in such circumstances is increased because the
Company would be obligated to meet fixed payment obligations on
specified dates regardless of the Company’s revenue. If the
Company does not make its debt service payments when due, the
Company may sustain the loss of its equity investment in any of
the Company’s assets securing such debt, upon the
foreclosure on such debt by a secured lender. The interest
payable on the Company’s debt varies with the movement of
interest rates charged by financial institutions. An increase in
the Company’s borrowing costs due to a rise in interest
rates in the market may reduce the amount of income and cash
available for the payment of dividends to the holders of the
Company’s common stock.
The Company’s financial position and past financial
performance could have the following material adverse
consequences for its business:
Effective internal controls are necessary for the Company to
provide reliable financial reports, prevent fraud and operate
successfully as a public company. The Company cannot be certain
that its efforts to maintain its internal controls will be
successful, that it will be able to maintain adequate controls
over its financial processes and reporting in the future or that
it will be able to comply with its obligations under
Section 404 of the Sarbanes-Oxley Act of 2002. Any failure
to develop or maintain effective internal controls or
difficulties encountered in implementing or improving the
Company’s internal controls could harm its operating
results or cause it to fail to meet its reporting obligations.
Ineffective internal controls also could cause the
Company’s shareholders and potential investors to lose
confidence in the Company’s reported financial information,
which would likely have a negative effect on the trading price
of its common stock.
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The operating and financial restrictions and covenants in the
Company’s credit agreements could restrict its ability to
finance future operations or capital needs or to engage, expand
or pursue its business activities or to pay distributions. The
Company’s credit agreements restrict its ability to:
The Company is also required to comply with certain financial
covenants and ratios. The Company’s ability to comply with
these restrictions and covenants in the future is uncertain and
will be affected by its results of operations and financial
conditions and events or circumstances beyond its control. If
market or other economic conditions deteriorate, the
Company’s ability to comply with these covenants may be
impaired. If the Company violates any of the restrictions,
covenants, ratios or tests in its credit agreements, a
significant portion of its indebtedness may become immediately
due and payable, its ability to make distributions will be
inhibited and the lenders’ commitment to make further loans
to the Company may terminate. The Company might not have, or be
able to obtain, sufficient funds to make these accelerated
payments. In addition, the Company’s obligations under its
credit agreements are secured by substantially all of its
assets, and if it is unable to repay indebtedness under its
credit agreements, the lenders could seek to foreclose on its
assets.
The Company’s credit agreements limit the amounts it can
borrow to a borrowing base amount, determined by the lenders in
their sole discretion. Outstanding borrowings in excess of the
borrowing base will be required to be repaid (1) within
90 days following receipt of notice of the new borrowing
base or (2) immediately if the borrowing base is reduced in
connection with a sale or disposition of certain properties in
excess of 5% of the borrowing base. Additionally, if the
lenders’ exposure under letters of credit exceeds the
borrowing base after all borrowings under the credit agreements
have been repaid, the Company will be required to provide
additional cash collateral.
Terrorist
attacks, and the threat of terrorist attacks, have resulted in
increased costs to the Company’s business. Continued
hostilities in the Middle East or other sustained military
campaigns may adversely impact the Company’s results of
operations.
The long-term impact of terrorist attacks, such as the attacks
that occurred on September 11, 2001, and the threat of
future terrorist attacks on the Company’s industry in
general, and on the Company in particular, is not known at this
time. Uncertainty surrounding continued hostilities in the
Middle East or other sustained military campaigns may affect the
Company’s operations in unpredictable ways, including
disruptions of crude oil supplies and markets for refined
products, and the possibility that infrastructure facilities
could be direct targets of, or indirect casualties of, an act of
terror.
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Risks
Relating to the Company’s Common Stock
The Company cannot assure you that an active public market for
the Company’s common stock will develop in the future. The
following factors could affect the Company’s stock price:
The Company cannot predict with certainty that its operations
will result in sufficient revenues to enable it to operate
profitably and with sufficient positive cash flow so as to
enable the Company to pay dividends to the holders of common
stock. In addition, the Company’s credit facilities
generally prohibit it from paying any dividend to the holders of
the Company’s common stock without the consent of the
lenders under the credit facilities, other than dividends
payable solely in equity interests of the Company.
The Company is authorized to issue up to 200,000,000 shares
of common stock and is not prohibited from issuing additional
shares of such common stock. Moreover, to the extent that the
Company issues any additional common stock, a holder of the
common stock is not necessarily entitled to purchase any part of
such issuance of stock. The holders of the common stock do not
have statutory “preemptive rights” and therefore are
not entitled to maintain a proportionate share of ownership by
buying additional shares of any new issuance of common stock
before others are given the opportunity to purchase the same.
Accordingly, you must be willing to assume the risk that your
percentage ownership, as a holder of the common stock, is
subject to change as a result of the sale of any additional
common stock, or other equity interests in the Company
subsequent to this offering.
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As an equity interest, the common stock will not be secured by
any of the Company’s assets. Therefore, in the event of the
Company’s liquidation, the holders of the common stock will
receive a distribution only after all of the Company’s
secured and unsecured creditors have been paid in full. There
can be no assurance that the Company will have sufficient assets
after paying its secured and unsecured creditors to make any
distribution to the holders of the common stock.
Certain provisions of Nevada law may delay, discourage, prevent
or render more difficult an attempt to obtain control of the
Company, whether through a tender offer, business combination,
proxy contest or otherwise. The provisions of Nevada law are
designed to discourage coercive takeover practices and
inadequate takeover bids. These provisions are also designed to
encourage persons seeking to acquire control of the Company to
first negotiate with the Company’s board of directors.
The Nevada Revised Statutes (the “NRS”) contain two
provisions, described below as “Combination
Provisions” and the “Control Share Act,” that may
make more difficult the accomplishment of unsolicited or hostile
attempts to acquire control of the Company through certain types
of transactions.
Restrictions on Certain Combinations Between Nevada
Resident Corporations and Interested
Stockholders. The NRS includes the
Combination Provisions prohibiting certain
“combinations” (generally defined to include certain
mergers, disposition of assets transactions, and share issuance
or transfer transactions) between a resident domestic
corporation and an “interested stockholder” (generally
defined to be the beneficial owner of 10% or more of the voting
power of the outstanding shares of the corporation), except
those combinations which are approved by the board of directors
before the interested stockholder first obtained a 10% interest
in the corporation’s stock. There are additional exceptions
to the prohibition, which apply to combinations if they occur
more than three years after the interested stockholder’s
date of acquiring shares. The Combination Provisions apply
unless the corporation elects against their application in its
original articles of incorporation or an amendment thereto. The
Company’s restated articles of incorporation do not
currently contain a provision rendering the Combination
Provisions inapplicable.
Nevada Control Share Act. Nevada’s
Control Share Act imposes procedural hurdles on and curtails
greenmail practices of corporate raiders. The Control Share Act
temporarily disenfranchises the voting power of “control
shares” of a person or group (“Acquiring Person”)
purchasing a “controlling interest” in an
“issuing corporation” (as defined in the NRS) not
opting out of the Control Share Act. In this regard, the Control
Share Act will apply to an “issuing corporation”,
unless the articles of incorporation or bylaws in effect on the
tenth day following the acquisition of a controlling interest
provide that it is inapplicable. The Company’s restated
articles of incorporation and bylaws do not currently contain a
provision rendering the Control Share Act inapplicable.
Under the Control Share Act, an “issuing corporation”
is a corporation organized in Nevada which has 200 or more
stockholders of record, at least 100 of whom have addresses in
that state appearing on the company’s stock ledger, and
which does business in Nevada directly or through an affiliated
company. The Company’s status at the time of the occurrence
of a transaction governed by the Control Share Act (assuming
that the Company’s articles of incorporation or bylaws have
not theretofore been amended to include an opting out provision)
would determine whether the Control Share Act is applicable. The
Company does not currently conduct any business in Nevada
directly or through an affiliated company.
The Control Share Act requires an Acquiring Person to take
certain procedural steps before he or it can obtain the full
voting power of the control shares. “Control shares”
are the shares of a corporation (1) acquired or offered to
be acquired which will enable the Acquiring Person to own a
“controlling interest,” and (2) acquired within
90 days immediately preceding that date. A
“controlling interest” is defined as the ownership of
shares which would enable the Acquiring Person to exercise
certain graduated amounts (beginning with one-fifth) of all
voting power of the corporation in the election of directors.
The Acquiring Person may not vote any control shares without
first obtaining approval from the stockholders not characterized
as “interested stockholders” (as defined below).
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To obtain voting rights in control shares, the Acquiring Person
must file a statement at the principal office of the issuer
(“Offeror’s Statement”) setting forth certain
information about the acquisition or intended acquisition of
stock. The Offeror’s Statement may also request a special
meeting of stockholders to determine the voting rights to be
accorded to the Acquiring Person. A special stockholders’
meeting must then be held at the Acquiring Person’s expense
within 30 to 50 days after the Offeror’s Statement is
filed. If a special meeting is not requested by the Acquiring
Person, the matter will be addressed at the next regular or
special meeting of stockholders.
At the special or annual meeting at which the issue of voting
rights of control shares will be addressed, “interested
stockholders” may not vote on the question of granting
voting rights to control the corporation or its parent unless
the articles of incorporation of the issuing corporation provide
otherwise. The Company’s restated articles of incorporation
and bylaws do not currently contain a provision allowing for
such voting power.
If full voting power is granted to the Acquiring Person by the
disinterested stockholders, and the Acquiring Person has
acquired control shares with a majority or more of the voting
power, then (unless otherwise provided in the articles of
incorporation or bylaws in effect on the tenth day following the
acquisition of a controlling interest) all stockholders of
record, other than the Acquiring Person, who have not voted in
favor of authorizing voting rights for the control shares, must
be sent a notice advising them of the fact and of their right to
receive “fair value” for their shares. The
Company’s restated articles of incorporation and bylaws do
not provide otherwise. By the date set in the dissenter’s
notice, which may not be less than 30 nor more than 60 days
after the dissenter’s notice is delivered, any such
stockholder may demand to receive from the corporation the
“fair value” for all or part of his shares. “Fair
value” is defined in the Control Share Act as “not
less than the highest price per share paid by the Acquiring
Person in an acquisition.”
The Control Share Act permits a corporation to redeem the
control shares in the following two instances, if so provided in
the articles of incorporation or bylaws of the corporation in
effect on the tenth day following the acquisition of a
controlling interest: (1) if the Acquiring Person fails to
deliver the Offeror’s Statement to the corporation within
10 days after the Acquiring Person’s acquisition of
the control shares; or (2) an Offeror’s Statement is
delivered, but the control shares are not accorded full voting
rights by the stockholders. The Company’s restated articles
of incorporation and bylaws do not address this matter.
None.
See Note 8 — Contingencies, in notes to
consolidated financial statements, which is incorporated herein
by reference.
No matters were submitted to a vote of security holders during
the fourth quarter of 2006.
Our common stock trades on The Nasdaq Global Market under the
symbol “QRCP”. During the period from January 1,
2005 until April 10, 2006, our common stock was traded on
the OTC Bulletin Board. Since April 10, 2006, the
Company’s common stock has traded on The Nasdaq Global
Market or its predecessor, The Nasdaq National Market
(collectively, “NASDAQ”).
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The table set forth below lists the range of high and low prices
of the Company’s common stock on NASDAQ since
April 11, 2006 and high and low bids on the OTC
Bulletin Board for each quarter of our last two fiscal
years. The high and low bids on the OTC Bulletin Board in
the table reflect inter-dealer prices, without retail markup,
markdown or commission and may not represent actual
transactions. Prices have been adjusted to give effect to the
2.5 to 1.0 reverse stock split that was effective
October 31, 2005.
The closing price for QRCP stock on March 6, 2007 was $8.00.
As of March 6, 2007, there were 22,206,014 shares of
common stock issued and outstanding, held of record by
approximately 880 shareholders.
The payment of dividends on our stock is within the discretion
of the board of directors and will depend on our earnings,
capital requirements, financial condition and other relevant
factors. We have not declared any cash dividends on our common
stock for the last two fiscal years and do not anticipate paying
any dividends on our common stock in the foreseeable future.
Our ability to pay dividends on our common stock is subject to
restrictions contained in our credit facilities. See
Item 7. “Management’s Discussion and of Financial
Conditions and Results of Operations — Capital
Resources and Liquidity” for a discussion of these
restrictions.
In addition, the partnership agreement for Quest Midstream
restricts the ability of Quest Midstream to pay distributions on
the class A and class B subordinated units that we own
if the minimum quarterly distribution has not been paid on all
of the Quest Midstream common units. See Items 1 and 2
“Description of Business and Properties — Recent
Events — First Amended and Restated Agreement of
Limited Partnership of Quest Midstream Partners, L.P.” for
additional information. The revolving credit facility for
Bluestem also restricts the ability of Bluestem to pay any
distributions if Bluestem is in default under the credit
facility.
In connection with the amendment to our third lien term loan
agreement, on December 22, 2006, we issued
82,500 shares of our common stock to the lenders under that
agreement as a portion of the fees owed to such lenders in
connection with the amendment. The shares were issued pursuant
to Rule 506 of Regulation D under the Securities Act
of 1933. In connection with the issuance of these shares, we
agreed to file a re-sale shelf registration statement on
Form S-3
with respect to these shares as soon as practicable, but in no
event later than January 19, 2006.
Purchases
of Equity Securities
None.
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The following graph compares the performance of our Common Stock
to a peer group in our SIC code index and to the Nasdaq market
index for the past five years. The graph assumes the investment
of $100 on December 31, 2001 and the reinvestment of all
dividends. The graph shows the value of the investment at the
end of each year.
COMPARISON
OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Quest Resource Corp, The NASDAQ Composite Index And A
Peer Group
• $100 invested on 12/31/01 in stock or
index-including reinvestment of dividends.
Fiscal year ending December 31.
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The following table sets forth selected consolidated financial
data of Quest for the years ended December 31, 2006 and
2005, the seven month transition period ended December 31,
2004 and the fiscal years ended May 31, 2004, 2003, and
2002. The data are derived from our audited consolidated
financial statements revised to reflect the reclassification of
certain items. Comparability between years is affected by
(1) changes in the annual average prices for oil and gas,
(2) increased production from drilling and development
activity and (3) significant acquisitions that were made
during the fiscal year ended May 31, 2004. The table should
be read in conjunction with “Management’s Discussion
and Analysis of Financial Condition and Results of
Operations” and our consolidated financial statements,
including the notes, appearing in Items 7 and 8 of this
report.
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Ratio of
Earnings to Combined Fixed Charges
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Financial
Data
The following table sets forth certain information regarding the
production volumes, oil and gas sales, average sales prices
received and expenses for the periods indicated:
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The following discussion of financial condition and results of
operations should be read in conjunction with the consolidated
financial statements and the notes to the consolidated financial
statements, which are included elsewhere in this report.
We are including the following discussion to inform you of some
of the risks and uncertainties that can affect our company and
to take advantage of the “safe harbor” protection for
forward-looking statements that applicable federal securities
law affords. Various statements this report contains, including
those that express a belief, expectation, or intention, as well
as those that are not statements of historical fact, are
forward-looking statements. These include such matters as:
When we use the words “believe,” “intend,”
“expect,” “may,” “will,”
“should,” “anticipate,” “could,”
“estimate,” “plan,” “predict,”
“project,” or their negatives, or other similar
expressions, the statements which include those words are
usually forward-looking statements. When we describe strategy
that involves risks or uncertainties, we are making
forward-looking statements. The forward-looking statements in
this report speak only as of the date of this report; we
disclaim any obligation to update these statements unless
required by securities law, and we caution you not to rely on
them unduly. We have based these forward-looking statements on
our current expectations and assumptions about future events.
While our management considers these expectations and
assumptions to be reasonable, they are inherently subject to
significant business, economic, competitive, regulatory and
other risks, contingencies and uncertainties, most of which are
difficult to predict and many of which are beyond our control.
All subsequent oral and written forward looking statements
attributable to the Company or persons acting on its behalf are
expressly qualified in their entirety by these factors. These
risks, contingencies and uncertainties relate to, among other
matters, the following:
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When you consider these forward-looking statements, you should
keep in mind these risk factors and the other factors discussed
under Item 1A. — “Risk Factors.”
Our strategic positioning in the southeastern Kansas and
northeastern Oklahoma natural gas industry has contributed to
increases in total revenues and has resulted in a solid
foundation for future growth. The increase in total revenues in
2006 as compared to calendar year 2005 resulted from an
approximate 28% increase in production volumes, which were
partially offset by lower product prices (before hedge
settlements) for natural gas.
At December 31, 2006, we had an interest in 1,653 natural
gas and oil wells (gross) and natural gas and oil leases on
approximately 542,000 gross acres. Management believes that
the proximity of the 1,600 miles of Quest Midstream owned
pipeline network to these natural gas and oil leases will enable
us to develop new producing wells on many of our undeveloped
properties. We have currently identified approximately 1,760
additional proved undeveloped natural gas well drilling sites on
our proved undeveloped acreage. With approximately
550 wells planned to be drilled during each of 2007 and
2008, we are positioned for significant growth in natural gas
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production, revenues, and net income. However, no assurance can
be given that we will be able to achieve our anticipated rate of
growth or that adequate sources of capital will be available.
The results of our drilling and well development program for
calendar year 2006 included the drilling of 622 new gas wells
(gross), the connecting of 638 new gas wells (gross) into our
gas gathering pipeline network, the construction of
approximately 392 miles of pipeline infrastructure and the
re-completion of 125 wells from single seam to multi-seam
wells.
On June 9, 2006, we and Quest Cherokee entered into a
$75 million six-year Third Lien Term Loan Agreement among
us, Quest Cherokee, Guggenheim Corporate Funding, LLC, as
administrative agent, and the lenders party thereto that was
fully funded at the closing. See Note 3 to our consolidated
financial statements included elsewhere in this report for
additional information regarding our third lien term loan
facility.
On December 22, 2006, Quest Midstream, a Delaware limited
partnership formed to own and operate our natural gas gathering
pipeline system, sold 4,864,866 common units, representing an
approximate 48.64% interest in Quest Midstream, for
$18.50 per common unit, or approximately $90 million,
pursuant to a purchase agreement dated December 22, 2006,
to a group of institutional investors led by Alerian, and co-led
by Swank. See Items 1 and 2, “Description of
Business and Properties-Recent Events-Formation of Quest
Midstream.”
Results
of Operations
The following discussion of results of operations will compare
audited balances for the year ended December 31, 2006 to
the audited balances for the year ended December 31, 2005,
as follows:
Total revenues of $60.3 million for the year ended
December 31, 2006 represents an increase of 23% when
compared to total revenues of $48.9 million for the year
ended December 31, 2005. The increase in natural gas and
oil sales from $44.6 million for the year ended
December 31, 2005 to $65.6 million for the year ended
December 31, 2006 and the increase in natural gas pipeline
revenue from $3.9 million to $5.0 million resulted
from the additional wells and pipelines completed during the
past twelve months. The additional wells completed contributed
to the production of 12,282,000 mcf of net gas for the year
ended December 31, 2006, as compared to 9,565,000 net
mcf produced for the year ended December 31, 2005. Our
product prices before hedge settlements on an equivalent basis
(mcfe) decreased from $7.45 mcfe average for the 2005 period to
$5.95 mcfe average for the 2006 period. Accounting for hedge
settlements, the product prices decreased from $4.63 mcfe
average for the 2005 period to $4.48 mcfe average for the 2006
period. With our continuing well development program, management
expects the production and pipeline volumes to continue growing
in the foreseeable future. We seek to reduce natural gas price
volatility through the use of derivative financial instruments
or hedges. As of January 1, 2007, we had entered into
hedging transactions covering a total of approximately
20 Bcf of natural gas production through December 2008. See
Items 1 and 2 “Description of Business and
Properties — Delivery Commitments — Hedging
Activities” and Notes 14 and 15 to the consolidated
financial statements included in this report.
Other expense for the year ended December 31, 2006 was
$10.3 million that resulted from a reclassification from
gas sales of cash settlements for derivative contracts that did
not qualify as cash flow hedges as compared to other revenue of
$389,000 for the year ended December 31, 2005, that was
primarily the result of an adjustment of overhead fees.
The operating costs for the year ended December 31, 2006
totaled approximately $21.2 million as compared to
operating costs of approximately $14.4 million incurred for
the year ended December 31, 2005. Operating costs,
excluding gross production and ad valorem taxes, were
$1.29 per mcf for 2006 compared to $0.99 for the year ended
December 31, 2005. Operating costs, inclusive of gross
production and ad valorem taxes, were $1.84 per mcf for the
2006 period as compared to $1.57 per mcf for the year ended
December 31, 2005 period, representing a 16% increase.
Approximately 40% of this increase resulted from increased
property taxes on wells and pipelines in the State of Kansas,
due to an increase in tax valuations; approximately 15% of the
increase was due to increased gross production taxes from
increased production volumes and approximately 30% was due to a
decrease in the amount of
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field payroll allocated to capital expenditures due to the
limited amount of capital expenditures that we incurred during
the fourth quarter of 2006. Approximately 15% is due to an
increase in our treating program to reduce pump failures.
Pipeline operating costs for the year ended December 31,
2006 totaled approximately $13.2 million ($1.08 per
mcf) as compared to pipeline operating costs of
$8.5 million ($0.89 per mcf) for the year ended
December 31, 2005. Pipeline operating costs, excluding ad
valorem taxes, were $0.96 per mcf for 2006 as compared to
$0.82 per mcf for 2005. This increase in operating costs
was due to the delivery of additional compressors in
anticipation of increased pipeline volumes, the number of wells
completed and operated during the year, the increased miles of
pipeline in service and the increase in property taxes. The
increase in depreciation, depletion and amortization to
approximately $28.0 million in 2006 from approximately
$22.2 million in 2005 is a result of the increased number
of producing wells and miles of pipeline developed, the higher
volumes of natural gas and oil produced and the resulting
increased depletion rate. In 2007, we anticipate these operating
costs to decrease on a per mcf basis due to the increased
volumes forecasted from new wells completed last year and the
new wells to be completed in 2007.
General and administrative expenses increased to approximately
$8.8 million for the year ended December 31, 2006 from
$4.8 million in the year ended December 31, 2005 due
to an increase in board fees, professional fees, Nasdaq listing
fees, travel expenses for presentations to increase the
visibility of the Company, costs for establishing a Houston
office and staffing requirements, increased staffing to support
the higher levels of development and operational activity and
the added resources to enhance our internal controls and
financial reporting to comply with the requirement for the audit
of our internal control over financial reporting for the year
ended December 31, 2006 required under the Sarbanes-Oxley
Act of 2002. See Item 1A. “Risk Factors —
Risks Related to the Company’s Business.”
Interest expense decreased to approximately $23.5 million
for the year ended December 31, 2006 from
$26.4 million for the year ended December 31, 2005
(inclusive of a $4.3 million write-off of debt issue costs
realized in connection with the refinancing of our credit
facilities in 2005). Excluding the write-off of debt issue costs
in 2005, the approximate $1.4 million increase in interest
expense in 2006 was due to higher average outstanding
borrowings, partially offset by lower average interest rates
under our new credit facilities that were entered into in
November 2005.
Change in derivative fair value was a non-cash gain of
$16.6 million for the year ended December 31, 2006,
which included a $12.2 million gain attributable to the
change in fair value for certain derivative contracts that did
not qualify as cash flow hedges pursuant to SFAS 133 and a
gain of $4.4 million relating to hedge ineffectiveness.
Change in derivative fair value was a non-cash net loss of
$4.7 million for the year ended December 31, 2005,
which included an $879,000 net gain attributable to the
change in fair value for certain cash flow hedges that did not
meet the effectiveness guidelines of SFAS 133 for the
period, a $103,000 net gain attributable to the reversal of
contract fair value gains and losses recognized in earnings
prior to actual settlement, and a loss of $5.7 million
relating to hedge ineffectiveness. Amounts recorded in this
caption represent non-cash gains and losses created by valuation
changes in derivatives that are not entitled to receive hedge
accounting. All amounts recorded in this caption are ultimately
reversed in this caption over the respective contract term.
We generated a net loss of $65.1 million (including
$23.5 million of interest expense and a $30.7 million
provision for impairment of oil and gas properties from a full
cost pool ceiling write-down) before income taxes and before the
change in derivative fair value of $16.6 million non-cash
net gain for the year ended December 31, 2006 as compared
to a net loss of $27.3 million (including
$26.4 million of interest expense) before income taxes and
before the change in derivative fair value of $4.7 million
non-cash net loss for the year ended December 31, 2005. No
income tax expense or benefit resulted for the years ended
December 31, 2006 or 2005. The provision for impairment is
primarily attributable to declines in estimated reserves due to
the prevailing market prices of oil and gas at the measurement
date.
We recorded a net loss of $48.5 million for the year ended
December 31, 2006 as compared to a net loss of
$31.9 million for the year ended December 31, 2005.
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Year
ended December 31, 2005 compared to the Year ended
December 31, 2004
Effective January 1, 2005, we changed our fiscal year-end
from May 31 to December 31. As a result of this
change, we prepared audited financial statements for the
seven-month transition period ended December 31, 2004.
Accordingly, the following discussion of results of operations
will compare audited balances for the year ended
December 31, 2005 to the unaudited balances for the year
ended December 31, 2004, as follows:
Total revenues of $48.9 million for the year ended
December 31, 2005 represents an increase of 6% when
compared to total revenues of $46.3 million for the year
ended December 31, 2004. The increase in natural gas and
oil sales from $42.4 million for the year ended
December 31, 2004 to $44.6 million for the year ended
December 31, 2005 and the increase in natural gas pipeline
revenue from $3.3 million to $3.9 million resulted
from the additional wells and pipelines acquired or completed
during the past twelve months. The additional wells acquired or
completed contributed to the production of 9,565,000 mcf of net
gas for the year ended December 31, 2005, as compared to
8,607,000 net mcf produced for the year ended
December 31, 2004. Our product prices before hedge
settlements on an equivalent basis (mcfe) increased from $5.63
mcfe average for the 2004 period to $7.45 mcfe average for the
2005 period. Accounting for hedge settlements, the product
prices decreased from $4.93 mcfe average for the 2004 period to
$4.63 mcfe average for the 2005 period, due to the significant
basis differential that occurred in the market during our fourth
quarter, resulting from the hurricanes in the United States.
Since new well development is once again an ongoing program,
management expects the production and pipeline volumes to
continue growing in the foreseeable future. We seek to reduce
natural gas price volatility through the use of derivative
financial instruments or hedges. As of January 1, 2006, we
had entered into hedging transactions covering a total of
approximately 14 Bcf of natural gas production through
December 2008. See Items 1 and 2 “Description of
Business and Properties — Company
Operations — Exploration & Production
Activities — Hedging Activities” and
Notes 14 and 15 to the consolidated financial statements
included in this report.
Other revenue for the year ended December 31, 2005 was
$389,000 as compared to other revenue of $632,000 for the year
ended December 31, 2004, resulting from recording the gain
or loss on hedge settlements for the two comparative periods.
The operating costs for the year ended December 31, 2005
totaled approximately $14.4 million as compared to
operating costs of approximately $9.5 million incurred for
the year ended December 31, 2004. Operating costs,
excluding gross production and ad valorem taxes, were
$0.99 per mcf for 2005 compared to $0.78 for the year ended
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December 31, 2004. Operating costs, inclusive of gross
production and ad valorem taxes, were $1.57 per mcf for the
2005 period as compared to $1.11 per mcf for the year ended
December 31, 2004 period, representing a 35% increase.
Approximately 30% of this increase resulted from increased
property taxes on wells and pipelines in the State of Kansas,
due to an increase in tax valuations; approximately 25% of the
increase was due to increased gross production taxes from
product price increases and approximately 30% was due to a
decrease in the amount of field payroll allocated to capital
expenditures due to the limited amount of capital expenditures
that we could incur under our prior credit facility during the
last half of year 2005. Additionally, approximately 3% relates
to workers compensation payments made in August 2005 as a result
of an audit of our 2004 payroll and approximately 12% is due to
an increase in the Company’s treating program to reduce
pump failures. Pipeline operating costs for the year ended
December 31, 2005 totaled approximately $8.5 million
($0.89 per mcf) as compared to pipeline operating costs of
$5.7 million ($0.66 per mcf) for the year ended
December 31, 2004. Pipeline operating costs, excluding ad
valorem taxes, were $0.82 per mcf for 2005 as compared to
$0.64 per mcf for 2004. This increase in operating costs
was due to the delivery of additional compressors in
anticipation of increased pipeline volumes, the number of wells
acquired, completed and operated during the year and the
increased miles of pipeline in service. The increase in
depreciation, depletion and amortization to approximately
$22.2 million in 2005 from approximately $13.9 million
in 2004 is a result of the increased number of producing wells
and miles of pipeline acquired and developed, the higher volumes
of natural gas and oil produced and the resulting increased
depletion rate and development costs. In 2006, we anticipate
these operating costs to decrease on a per mcf basis due to the
increased volumes forecasted from our aggressive development
program.
General and administrative expenses increased to approximately
$4.8 million for the year ended December 31, 2005 from
$4.4 million in the year ended December 31, 2004 due
primarily to the increased staffing in the fourth quarter to
support the higher levels of development and operational
activity and the added resources to enhance the Company’s
internal controls and financial reporting in anticipation of the
Company having to comply with the requirement for an audit of
our internal control over financial reporting for the year ended
December 31, 2006 required under the Sarbanes-Oxley Act of
2002. See Item 1A. “Risk Factors — Risks
Related to the Company’s Business.”
Interest expense increased to approximately $26.4 million
(inclusive of a $4.3 million write off of amortizing bank
fees realized in connection with the refinancing of our credit
facilities) for the year ended December 31, 2005 from
$15.9 million for the year ended December 31, 2004,
due to an increase in interest rates and due to the increase in
the Company’s outstanding borrowings related to the
compounding of interest under the subordinated notes and
equipment, development and leasehold expenditures from the
Company’s drilling and development program and the
associated build out of pipeline systems.
Change in derivative fair value was a non-cash net loss of
$4.7 million for the year ended December 31, 2005,
which included a $879,000 net gain attributable to the
change in fair value for certain cash flow hedges that did not
meet the effectiveness guidelines of SFAS 133 for the
period, a $103,000 net gain attributable to the reversal of
contract fair value gains and losses recognized in earnings
prior to actual settlement, and a loss of $5.7 million
relating to hedge ineffectiveness. Change in derivative fair
value was a non-cash net loss of $6.8 million for the year
ended December 31, 2004, which included a $5.0 million
net loss attributable to the change in fair value for certain
cash flow hedges that did not meet the effectiveness guidelines
of SFAS 133 for the period, a $1.4 million net gain
attributable to the reversal of contract fair value gains and
losses recognized in earnings prior to actual settlement, and a
loss of $3.2 million relating to hedge ineffectiveness.
Amounts recorded in this caption represent non-cash gains and
losses created by valuation changes in derivatives that are not
entitled to receive hedge accounting. All amounts recorded in
this caption are ultimately reversed in this caption over the
respective contract term.
We generated a net loss of $27.3 million (including
$26.4 million of interest expense) before income taxes and
before the change in derivative fair value of $4.7 million
for the year ended December 31, 2005, compared to a net
loss of $3.1 million (including $15.9 million of
interest expense) before income taxes and before the change in
derivative fair value of $6.8 million in the year ended
December 31, 2004.
No income tax expense or benefit resulted for the years ended
December 31, 2005 or 2004.
We recorded a net loss of $31.9 million for the year ended
December 31, 2005 as compared to a net loss of
$9.9 million for the year ended December 31, 2004.
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As a result of the change in our fiscal year effective
January 1, 2005, we have prepared financial statements for
the seven-month transition period ended December 31, 2004.
Accordingly, the following discussion of results of operations
will compare audited balances for the seven months ended
December 31, 2004 to the unaudited balances for the seven
months ended December 31, 2003, as follows:
Total revenues of $26.2 million for the seven months ended
December 31, 2004 represents an increase of 201% when
compared to total revenues of $8.7 million for the seven
months ended December 31, 2003. This increase was achieved
by a combination of the additional producing wells from the
Devon acquisition in December 2003 and the Company’s
aggressive new well development program that was in effect
during the 2003 and 2004 fiscal years.
The increase in natural gas and oil sales from $8.8 million
for the seven months ended December 31, 2003 to
$24.2 million for the seven months ended December 31,
2004 and the increase in natural gas pipeline revenue from
$1.3 million to $1.9 million resulted from the Devon
asset acquisition and the additional wells and pipelines
acquired or completed during the twelve month period ended
December 31, 2004. The Devon asset acquisition and the
additional wells acquired or completed contributed to the
production of 5,014,000 mcf of net gas for the seven months
ended December 31, 2004, as compared to 1,815,000 net mcf
produced for the seven months ended December 31, 2003. Our
product prices before hedge settlements on an equivalent basis
(mcfe) increased from $4.82 mcfe average for the 2003 period to
$5.74 mcfe average for the 2004 period. Accounting for hedge
settlements, the product prices increased from $4.08 mcfe
average for the 2003 period to $4.83 mcfe average for the 2004
period. Since new well development is once again an ongoing
program, management expects the production and pipeline volumes
to continue growing in the foreseeable future. We seek to reduce
natural gas price volatility through the use of derivative
financial instruments or hedges. As of January 1, 2005, we
had entered into hedging transactions covering a total of
approximately 22.5 Bcf of natural gas production through
December 2008. See Items 1 and 2 “Description of
Business and Properties — Company
Operations — Exploration & Production
Activities — Hedging Activities” and
Notes 14 and 15 to the consolidated financial statements
included in this report.
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Other revenue for the seven months ended December 31, 2004
was $37,000 as compared to other expense of $1.4 million
for the seven months ended December 31, 2003, resulting
from recording the gain or loss on hedge settlements for the two
comparative periods.
The operating costs for the seven months ended December 31,
2004 totaled approximately $5.4 million as compared to
operating costs of approximately $2.3 million incurred for
the seven months ended December 31, 2003. Operating costs
per mcf for the 2004 period were $1.07 per mcf as compared
to $1.25 per mcf for the 2003 period, representing a 14%
decrease. Pipeline operating costs for the seven months ended
December 31, 2004 totaled approximately $3.7 million
as compared to pipeline operating costs of $1.1 million
incurred for the seven months ended December 31, 2003. The
increase in operating costs are due to the Devon asset
acquisition and the number of wells acquired, completed and
operated during the year and the increased miles of pipeline in
service. The increase in depreciation, depletion and
amortization to approximately $7.7 million from
approximately $2 million is a result of the increased
number of producing wells and miles of pipeline acquired and
developed, the higher volumes of natural gas and oil produced
and the higher cost of properties recorded by application of the
purchase method of accounting to record the Devon asset
acquisition.
General and administrative expenses increased to approximately
$2.7 million for the seven months ended December 31,
2004 from $831,000 in the prior seven month period due primarily
to the Devon asset acquisition, the increased staffing to
support the higher levels of development and operational
activity and the added resources to enhance the Company’s
internal controls and financial reporting in anticipation of the
Company having to comply with the requirement for an audit of
our internal control over financial reporting for the year ended
December 31, 2006 required under the Sarbanes-Oxley Act of
2002. See Item 1A. “Risk Factors — Risks
Related to the Company’s Business”.
Interest expense increased to approximately $10.1 million
for the seven months ended December 31, 2004 from
$2.4 million for the seven months ended December 31,
2003, due to the increase in our outstanding borrowings related
to the Devon acquisition and equipment, development and
leasehold expenditures from our aggressive drilling and
development program during the transition period.
Change in derivative fair value was a non-cash net loss of
$1.5 million for the seven months ended December 31,
2004, which included a $269,000 net loss attributable to
the change in fair value for certain cash flow hedges which did
not meet the effectiveness guidelines of SFAS 133 for the
period, a $565,000 net gain attributable to the reversal of
contract fair value gains and losses recognized in earnings
prior to actual settlement, and a loss of $1.8 million
relating to hedge ineffectiveness. Change in derivative fair
value was a non-cash net gain of $3.3 million for the seven
months ended December 31, 2003, which was attributable to
the change in fair value of cash flow hedges that did not meet
the effectiveness guidelines of SFAS 133 for the period.
Amounts recorded in this caption represent non-cash gains and
losses created by valuation changes in derivatives that are not
entitled to receive hedge accounting. All amounts recorded in
this caption are ultimately reversed in this caption over the
respective contract term.
We generated a net loss of $3.4 million before income taxes
and before the change in derivative fair value of
$1.5 million for the seven months ended December 31,
2004, compared to a net loss of $154,000 before income taxes and
before the change in derivative fair value of $3.3 million
in the previous seven month period.
No income tax expense or benefit resulted for the seven months
ended December 31, 2004 compared to income tax expense of
$1.3 million for the seven months ended December 31,
2003, inclusive of a tax benefit of approximately $620,000 and
the resulting limitation of net operating loss carry forwards,
both resulting from the acquisition of STP Cherokee, Inc. in
November 2002.
We recorded a net loss of $4.9 million for the seven months
ended December 31, 2004 as compared to net income of
$1.9 million for the seven months ended December 31,
2003.
Total revenues of $30 million for the year ended
May 31, 2004 represents an increase of 271% when compared
to total revenues of $8.1 million for the fiscal year ended
May 31, 2003. This increase was achieved by a combination
of the additional producing wells from the Devon acquisition in
December 2003, the Perkins/Willhite
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acquisition in June 2003, the STP Cherokee acquisition in
November 2002 and the Company’s aggressive new well
development program during both periods.
The increase in natural gas and oil sales from $8.3 million
in fiscal year 2003 to $28.1 million in fiscal year 2004
and the increase in natural gas pipeline revenue from $632,000
to $2.7 million resulted from the Devon, STP Cherokee and
the Perkins/Willhite acquisitions and the additional wells and
pipelines acquired or completed during the 2004 fiscal year. The
Devon, STP Cherokee and Perkins/Willhite acquisitions and the
additional wells acquired or completed contributed to the
production of 5,530,208 mcf of net gas in fiscal year 2004, as
compared to 1,488,679 net mcf produced in the prior fiscal
year. Our product prices on an equivalent basis (mcfe) decreased
from $5.30 mcfe average for 2003 to $5.04 average for 2004.
Since new well development is once again an ongoing program,
management expects the production and pipeline volumes to
continue growing in the foreseeable future. We seek to reduce
natural gas price volatility through the use of derivative
financial instruments or hedges. As of June 1, 2004, we had
entered into hedging transactions covering a total of
approximately 16.6 Bcf of natural gas production through
December 2006. Subsequent to May 31, 2004, in connection
with the establishment of new credit facilities with UBS in July
2004, we entered into additional hedging transactions covering
approximately 10.2 Bcf of natural gas production through
December 2008. See Items 1 and 2 “Description of
Business and Properties — Company
Operations — Exploration & Production
Activities — Hedging Activities” and
Notes 14 and 15 to the consolidated financial statements
included in this report.
Other expense for the fiscal year ended May 31, 2004 was
$843,000 as compared to other expense of $879,000 for the fiscal
year ended May 31, 2003, resulting from recording the loss
on hedge settlements for the two comparative periods.
The operating costs for fiscal year ended May 31, 2004
totaled approximately $6.8 million as compared to operating
costs of approximately $1.9 million incurred for fiscal
year ended May 31, 2003. Operating costs per mcf for fiscal
year May 31, 2004 were $1.24 per mcf as compared to
$1.29 per mcf for fiscal year ended May 31, 2003,
representing a 4% decrease. Pipeline operating costs for fiscal
year ended May 31, 2004 totaled approximately
$3.5 million as compared to pipeline operating costs of
$912,000 incurred for fiscal year ended May 31, 2003. The
increase in operating costs are due to the Devon, STP Cherokee
and Perkins/Willhite acquisitions and the number of wells
acquired, completed and operated during the year and the
increased miles of pipeline in service. The increase in
depreciation, depletion and amortization to approximately
$7.7 million from approximately $1.8 million is a
result of the increased number of producing wells and miles of
pipelines acquired and developed, the higher volumes of natural
gas and oil produced and the higher cost of properties recorded
by application of the purchase method of accounting to record
the Devon, STP Cherokee and Perkins/Willhite acquisitions.
General and administrative expenses increased to approximately
$2.6 million in fiscal year 2004 from $977,000 in the prior
year due primarily to the Devon, STP and Perkins/Willhite
acquisitions, the increased staffing to support the higher
levels of development and operational activity and the added
resources to enhance the Company’s internal controls and
financial reporting.
Interest expense increased to approximately $8.1 million
for fiscal year 2004 from $727,000 for fiscal year 2003, due to
the increase in the Company’s outstanding borrowings
related to the Devon, STP and Perkins/Willhite acquisitions and
equipment, development and leasehold expenditures and the
expense of $1 million related to the refinancing of the
Company’s credit facilities that were in place at the time
of the Devon acquisition.
Change in derivative fair value was a non-cash net loss of
$2 million for the fiscal year ended May 31, 2004,
which included a $1.7 million net loss attributable to the
change in fair value for certain cash flow hedges that did not
meet the effectiveness guidelines of SFAS 133 for the
fiscal year, a $888,000 net gain attributable to the
reversal of contract fair value gains and losses recognized in
earnings prior to actual settlement, and a loss of
$1.2 million relating to hedge ineffectiveness. Change in
derivative fair value was a non-cash net loss of
$4.9 million for the year ended May 31, 2003, which
was attributable to the change in fair value of cash flow hedges
that did not meet the effectiveness guidelines of SFAS 133
for the year. Amounts recorded in this caption represent
non-cash gains and losses created by valuation changes in
derivatives which are not entitled to receive hedge accounting.
All amounts recorded in this caption are ultimately reversed in
this caption over the respective contract term.
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We generated income of $1.4 million before income taxes and
before the change in derivative fair value of $2 million
for fiscal year 2004, compared to income of approximately
$1.7 million before income taxes and before the change in
derivative fair value of $4.9 million in the previous
fiscal year.
The income tax benefit for the fiscal year ended May 31,
2004 was $245,000 compared to the income tax expense of $374,000
for the fiscal year ended May 31, 2003, inclusive of a tax
benefit of approximately $620,000 and the resulting limitation
of net operating loss carry forwards, both resulting from the
STP Cherokee acquisition.
We recorded a net loss of $393,000 for fiscal year 2004 as
compared to a net loss of approximately $3.6 million for
fiscal year 2003.
Capital
Resources and Liquidity
Analysis of cash flows. The following analysis
of cash flows will compare audited balances for the year ended
December 31, 2006 to the audited balances for the year
ended December 31, 2005, as follows:
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At December 31, 2006, we had current assets of
$59.9 million, working capital (current assets minus
current liabilities, excluding the short-term derivative asset
and liability of $10.8 million and $5.2 million,
respectively) of $37.7 million and had used
$13.5 million net cash from operations during the year
ended December 31, 2006.
During the year ended December 31, 2006, a total of
approximately $172.6 million was invested in new natural
gas wells and properties, new pipeline facilities, and other
additional capital items. This investment was funded through
approximately $40 million of the net proceeds from the
issuance of common units of Quest Midstream to a group of
investors, $200 million of bank borrowings during 2006 and
$511,000 from the issuance of common stock. Net cash used by
operating activities increased substantially from
$4.9 million for the year ended December 31, 2005 to
$13.5 million of net cash used for the year ended
December 31, 2006 due primarily to an increase in operating
costs and the fact that we expanded our operations during 2006.
Our working capital (current assets minus current liabilities,
excluding the short-term derivative asset and liability of
$10.8 million and $5.2 million, respectively) was
$37.7 million at December 31, 2006, compared to
working capital of $3.1 million, (excluding the short-term
derivative asset and liability of $95,000 and
$38.2 million, respectively) at December 31, 2005. The
change in working capital is due to the formation of Quest
Midstream in December 2006 and the issuance of common units in
Quest Midstream to a group of investors for approximately
$90 million before expenses. Additionally, inventory,
accounts payable and accrued expenses balances increased as we
expanded our operations.
During 2007, we intend to focus on drilling and completing
approximately 550 additional new wells. We also currently intend
to drill approximately 550 wells during 2008. Management
currently estimates that it will require over the next two years
a capital investment of approximately $113 million per year
to drill and develop these wells and for the pipeline expansion
to connect the new wells to our existing gas gathering pipeline
network. Management currently estimates that it will be able to
drill and develop the approximately 550 new wells planned for
2007 utilizing cash flow from operations, remaining cash from
the Quest Midstream transaction, available borrowings under the
revolving credit facility
and/or the
sale of additional equity interests. In addition, in the near
term, we intend to fund additional pipeline expansion to connect
these new wells to our gas gathering system with Bluestem’s
new $75 million revolving credit facility that was closed
in January 2007. The Company intends to finance capital
expenditures during 2008 utilizing a combination of cash flow
from operations, additional borrowings
and/or the
sale of equity. However, no assurances can be given that such
sources will be sufficient to fund the proposed capital
expenditures. We are currently
49
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seeking to raise additional equity capital to decrease the
amount of our debt as a percentage of our total capitalization.
However, there can be no assurance that we will be able to
obtain such additional equity capital on terms that are
favorable to us.
At December 31, 2006, $569,000 of notes payable to banks
and finance companies were outstanding and are secured by
equipment and vehicles, with payments due in monthly
installments through October 2013 with interest ranging from
5.5% to 11.5% per annum.
Future payments due on our contractual obligations as of
December 31, 2006 are as follows:
Certain amounts included in or affecting our consolidated
financial statements and related disclosures must be estimated,
requiring us to make certain assumptions with respect to values
or conditions that cannot be known with certainty at the time
the financial statements are prepared. These estimates and
assumptions affect the amounts we report for assets and
liabilities and our disclosure of contingent assets and
liabilities at the date of our financial statements. We
routinely evaluate these estimates, utilizing historical
experience, consultation with experts and other methods we
consider reasonable in the particular circumstances.
Nevertheless, actual results may differ significantly from our
estimates. Any effects on our business, financial position or
results of operations resulting from revisions to these
estimates are recorded in the period in which the facts that
give rise to the revision become known.
In preparing our consolidated financial statements and related
disclosures, we must use estimates in determining the economic
useful lives of our assets, the fair values used to determine
possible asset impairment charges, provisions for uncollectible
accounts receivable, exposures under contractual
indemnifications and various other recorded or disclosed
amounts. However, we believe that certain accounting policies
are of more significance in our consolidated financial statement
preparation process than others, which policies are discussed
following. See also Note 1 to the consolidated financial
statements for a summary of our significant accounting policies.
Estimated Net Recoverable Quantities of Natural Gas and
Oil. We use the full cost method of
accounting for our natural gas and oil producing activities. The
full cost method inherently relies on the estimation of proved
reserves, both developed and undeveloped. The existence and the
estimated amount of proved reserves affect, among other things,
the amount and timing of costs depleted or amortized into income
and the presentation of supplemental information on oil and gas
producing activities. The expected future cash flows to be
generated by
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natural gas and oil producing properties used in testing for
impairment of such properties also rely in part on estimates of
net recoverable quantities of natural gas and oil.
Our estimation of net recoverable quantities of natural gas and
oil is a highly technical process. Independent natural gas and
oil consultants have reviewed the estimates of proved reserves
of natural gas and crude oil that we have attributed to our net
interest in natural gas and oil properties as of
December 31, 2006.
Proved reserves are the estimated quantities of natural gas and
oil that geologic and engineering data demonstrates with
reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating
conditions. Estimates of proved reserves may change, either
positively and negatively, as additional information becomes
available and as contractual, economic and political conditions
change.
Hedging Activities. We engage in a
hedging program to mitigate our exposure to fluctuations in
commodity prices and we believe that these hedges are generally
effective in realizing this objective. However, the accounting
standards regarding hedge accounting are very complex, and even
when we engage in hedging transactions that are effective
economically, these transactions may not be considered effective
for accounting purposes. Accordingly, our financial statements
may reflect some volatility due to these hedges, even when there
is no underlying economic impact at that point. Generally, the
financial statement volatility arises from an accounting
requirement to recognize changes in values of financial
instruments while not concurrently recognizing the values of the
underlying transactions being hedged.
In addition, it is not always possible for us to engage in a
hedging transaction that completely mitigates our exposure to
commodity prices. For example, when we purchase a commodity at
one location and sell it at another, we may be unable to hedge
completely our exposure to a differential in the price of the
product between these two locations. Even when we cannot enter
into a completely effective hedge, we often enter into hedges
that are not completely effective in those instances where we
believe to do so would be better than not hedging at all. Our
financial statements may reflect a gain or loss arising from an
exposure to commodity prices for which we are unable to enter
into a completely effective hedge.
Legal Matters. We are subject to
litigation and regulatory proceedings as a result of our
business operations and transactions. We utilize internal
personnel and external counsel in evaluating our potential
exposure to adverse outcomes from orders, judgments or
settlements. To the extent that actual outcomes differ from our
estimates, or additional facts and circumstances cause us to
revise our estimates, our earnings will be affected. We expense
legal costs as incurred, and all recorded legal liabilities are
revised as better information becomes available.
Environmental Matters. With respect to
our environmental exposure, we utilize both internal staff and
external experts to assist us in identifying environmental
issues and in estimating the costs and timing of remediation
efforts. We routinely conduct reviews of potential environmental
issues and claims that could impact our assets or operations.
Often, as the remediation evaluation and effort progresses,
additional information is obtained, requiring revisions to
estimated costs. These revisions are reflected in our income in
the period in which they are reasonably determinable.
At December 31, 2006, we did not have any relationships
with unconsolidated entities or financial partnerships, such as
entities often referred to as structured finance or special
purpose entities, which would have been established for the
purpose of facilitating off-balance sheet arrangements or other
contractually narrow or limited purposes. In addition, we do not
engage in trading activities involving non-exchange traded
contracts. As such, we are not exposed to any financing,
liquidity, market, or credit risk that could arise if we had
engaged in such activities.
See Notes 14 and 15 to our consolidated financial
statements which are included elsewhere in this report and
incorporated herein by reference.
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Please see the accompanying financial statements attached hereto
beginning on
page F-1.
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To the Board of Directors and Stockholders
Quest Resource Corporation
We have audited the accompanying consolidated balance sheets of
QUEST RESOURCE CORPORATION and subsidiaries as of
December 31, 2006 and 2005, and the related consolidated
statements of operations, stockholders’ equity, and cash
flows for the year ended December 31, 2006 and 2005, the
seven months ended December 31, 2004 and the year ended
May 31, 2004. These consolidated financial statements are
the responsibility of the Company’s management. Our
responsibility is to express an opinion on these consolidated
financial statements based on our audits.
Consolidated
Financial Statements
We conducted our audits in accordance with the 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 misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the consolidated financial statements, assessing
the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides 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 Quest Resource Corporation
and subsidiaries as of December 31, 2006 and 2005 and 2004,
and the consolidated results of their operations and cash flows
for the year ended December 31, 2005, the seven months
ended December 31, 2004 and the year ended May 31,
2004, in conformity with accounting principles generally
accepted in the United States of America.
Internal
Control Over Financial Reporting
Also, in our opinion, management’s assessment, included in
Management’s Report on Internal Control Over Financial
Reporting appearing under Item 9A, that the Company
maintained effective internal control over financial reporting
as of December 31, 2006 based on criteria established in
Internal Control — Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO), is fairly stated, in all material respects,
based on those criteria. Furthermore, in our opinion, the
Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2006,
based on criteria established in Internal Control —
Integrated Framework issued by the COSO. The Company’s
management is responsible for maintaining effective internal
control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting. Our
responsibility is to express opinions on management’s
assessment and on the effectiveness of the Company’s
internal control over financial reporting based on our audit. We
conducted our audit of internal control over financial reporting
in accordance with the 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 effective internal control over
financial reporting was maintained in all material respects. An
audit of internal control over financial reporting includes
obtaining an understanding of internal control over financial
reporting, evaluating management’s assessment, testing and
evaluating the design and operating effectiveness of internal
control, and performing such other procedures as we consider
necessary in the circumstances. We believe that our audit
provides a reasonable basis for our opinions.
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A company’s 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 for external purposes in accordance with
generally accepted accounting principles. A company’s
internal control over financial reporting includes those
policies and procedures that (i) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (ii) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of
financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the
company are being made only in accordance with authorizations of
management and directors of the company; and (iii) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
company’s assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are 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.
/s/ MURRELL,
HALL, MCINTOSH & CO., PLLP
Oklahoma City, Oklahoma
March 7, 2007
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QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEETS
The accompanying notes are an integral part of these
consolidated financial statements
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QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these
consolidated financial statements
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QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS
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