4. NATURAL GAS PRICE HEDGING
The company periodically hedges the price of a portion of its estimated
natural gas production when the potential for significant downward price
movement is anticipated. Hedging
transactions typically take the form of forward short positions and collars on
the NYMEX futures market, and are closed by purchasing offsetting
positions. Such hedges, which are
accounted for as cash flow hedges, do not exceed estimated production volumes,
are expected to have reasonable correlation between price movements in the
futures market and the cash markets where the companys production is located,
and are authorized by the companys Board of Directors. Hedges are expected to be closed as related
production occurs but may be closed earlier if the anticipated downward price
movement occurs or if the company believes that the potential for such movement
has abated.
The company recognizes all derivatives (consisting solely of cash flow
hedges) on its balance sheet at fair value at the end of each period. Changes in the fair value of a cash flow
hedge are recorded in Stockholders Equity as Accumulated Other Comprehensive
Income on the Consolidated Balance Sheets and then are transferred into the
Consolidated Statement of Operations as the underlying hedged item affects
earnings. Amounts reclassified into
earnings related to natural gas hedges are included in oil and gas sales.
Hedging
gains and losses are recognized as adjustments to gas sales as the hedged
product is produced. The company had
hedging gains of $847,000 ($601,000 net of income tax) and $396,000 ($284,000
net of income tax) in the three months ended January 31, 2008 and 2007,
respectively. Any hedge ineffectiveness,
which was not material for any period, is immediately recognized in gas sales.
Open
hedge contracts are indexed to the NYMEX.
Periodically, the company enters into contracts indexed to Panhandle
Eastern Pipeline Company for Texas, Oklahoma mainline. For comparative purposes, hedges indexed to
Panhandle Eastern Pipeline Company are expressed on a NYMEX basis. For hedges indexed to Panhandle Eastern
Pipeline Company, the individual month price (basis) differentials between the
NYMEX and Panhandle Eastern Pipeline Company range from minus $1.45 in the
winter months to minus $0.90 in the spring months.
Unrecognized
gains and losses on hedge contracts at January 31, 2008 totaled a gain of
$127,000 ($91,000 after income tax) and were included in Other Comprehensive
Income. These contracts covered 1,420
MMBtus at average monthly NYMEX basis prices ranging from $7.83 to $9.42.
Subsequent
to January 31, 2008, the company entered into additional hedge contracts
covering 620 MMBtus at NYMEX basis prices, ranging from $8.13 to $9.95 for
the production months of October 2008 through October 2009.
The company has a hedging line of credit with its bank which is
available, at the discretion of the company, to meet margin calls. To date, the company has not used this
facility and maintains it only as a precaution related to possible margin
calls. The maximum credit line is
$5,900,000 with interest calculated at the prime rate. The facility is unsecured and has covenants
that require the company to maintain $3,000,000 in cash or short term
investments, none of which are required to be maintained at the companys bank,
and prohibits funded debt in excess of $500,000. It expires on November 15, 2010.
7
ITEM 2.
MANAGEMENTS
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q includes certain statements
that may be deemed to be forward-looking statements within the meaning of Section 27A
of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended.
All statements included in this Quarterly Report on Form 10-Q,
other than statements of historical facts, address matters that the company
reasonably expects, believes or anticipates will or may occur in the
future. Forward-looking statements may
relate to, among other things:
·
the companys future financial position, including working capital and
anticipated cash flow;
·
amounts and nature of future capital expenditures;
·
operating costs and other expenses;
·
wells to be drilled or reworked;
·
oil and natural gas prices and demand;
·
existing fields, wells and prospects;
·
diversification of exploration;
·
estimates of proved oil and natural gas reserves;
·
reserve potential;
·
development and drilling potential;
·
expansion and other development trends in the oil and natural gas
industry;
·
the companys business strategy;
·
production of oil and natural gas;
·
matters related to the Calliope Gas Recovery System;
·
effects of federal, state and local regulation;
·
insurance coverage;
·
employee relations;
·
investment strategy and risk; and
·
expansion and growth of the companys business and operations.
LIQUIDITY AND CAPITAL RESOURCES
At January 31, 2008, working capital
increased $3,192,000, or 34% to $12,643,000 compared to $9,451,000 at January 31,
2007. For the three months ended January 31,
2008, net cash provided by operating activities increased $87,000, or 6%, to $1,626,000
compared to net cash provided by operating activities of $1,539,000 for the
same period in 2007. Net income
increased $437,000 primarily due to an increase in revenues of $520,000, and a
decrease in total costs and expenses of $117,000, offset by an increase in
income taxes of $200,000.
For the three months ended January 31,
2008 and 2007, net cash used in investing activities was $3,203,000 and
$3,061,000, respectively. Investing
activities primarily included oil and gas exploration and development
expenditures, including Calliope, totaling $2,844,000 and $3,005,000
respectively.
The average return on the companys
investments was a loss of 1.2% for the three months ended January 31, 2008
compared to 4.5% return for the same period last year. At January 31, 2008, approximately 46% of
the investments were directly invested in mutual funds and were managed by
professional money managers. Remaining
investments are in managed partnerships (generally known as hedge funds) that
use various strategies to minimize their correlation to stock market
movements. Most of the investments are
highly liquid and the company believes they represent a responsible approach to
cash
10
management.
In the companys opinion, the greatest investment risk is the potential
for negative market impact from unexpected, major adverse news.
Existing
working capital and anticipated cash flow are expected to be sufficient to fund
operations and capital commitments for at least the next 12 months. At January 31, 2008, the company
had no lines of credit or other bank financing arrangements except for the
hedging line of credit discussed in Note 4. Because earnings are anticipated to be
reinvested in operations, cash dividends are not expected to be paid. The
company has no defined benefit plans and no obligations for post retirement
employee benefits.
The companys earnings before interest,
taxes, depreciation, depletion and amortization, (EBITDA) increased to
$3,391,000 for the three months ended January 31, 2008 from $2,864,000 for
the three months ended January 31, 2007. EBITDA is not a GAAP measure of operating
performance. The company uses this
non-GAAP performance measure primarily to compare its performance with other
companies in the industry that make a similar disclosure. The company believes that this performance
measure may also be useful to investors for the same purpose. Investors should not consider this measure in
isolation or as a substitute for operating income, or any other measure for
determining the companys operating performance that is calculated in
accordance with GAAP. In addition, because EBITDA is not a GAAP measure, it may
not necessarily be comparable to similarly titled measures employed by other
companies. A reconciliation between
EBITDA and net income is provided in the table below:
|
|
Three Months Ended January 31,
|
|
|
|
2008
|
|
2007
|
|
RECONCILIATION
OF EBITDA:
|
|
|
|
|
|
Net Income
|
|
$
|
1,801,000
|
|
$
|
1,364,000
|
|
Add Back:
|
|
|
|
|
|
Interest Expense
|
|
1,000
|
|
6,000
|
|
Income Tax
Expense
|
|
736,000
|
|
536,000
|
|
Depreciation,
Depletion and Amortization Expense
|
|
853,000
|
|
958,000
|
|
EBITDA
|
|
$
|
3,391,000
|
|
$
|
2,864,000
|
|
OFF-BALANCE SHEET FINANCING
The company has no significant off-balance sheet financing arrangements
at January 31, 2008.
PRODUCT PRICES AND PRODUCTION
Although product prices are key to the
companys ability to operate profitably and to budget capital expenditures,
they are beyond the companys control and are difficult to predict. Since 1991, the company has periodically
hedged the price of a portion of its estimated natural gas production when the
potential for significant downward price movement is anticipated. Hedging transactions typically take the form
of forward short positions, swaps and collars which are executed on the NYMEX
futures market or by indexing to regional index prices associated with
pipelines in proximity to the companys production. The companys current hedges are indexed to
NYMEX. Refer to Note 4 of the Consolidated
Financial Statements for a complete discussion on the companys hedging
activities.
11
Gas and oil sales volume and price realization comparisons for the
indicated periods are set forth below.
Price realizations include the sales price and the effect of hedging
transactions.
|
|
Three Months Ended January 31,
|
|
|
|
2008
|
|
2007
|
|
Change%
|
|
Product
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (Mcf)
|
|
392,000
|
|
$
|
8.24
|
(1)
|
528,000
|
|
$
|
6.03
|
(2)
|
-26
|
%
|
+37
|
%
|
Oil (bbls)
|
|
15,700
|
|
$
|
86.39
|
|
11,900
|
|
$
|
52.06
|
|
+31
|
%
|
+66
|
%
|
(1) Includes $2.16 per Mcf hedging gain.
(2) Includes $0.75 per Mcf hedging gain.
OPERATIONS
During the first quarter of fiscal 2008, the companys operations
continued to focus on its two core projects natural gas drilling and
application of its patented Calliope Gas Recovery System.
The
company believes that, in combination, its drilling and Calliope projects
provide an excellent (and possibly unique) balance for achieving its goal of
adding long-lived natural gas reserves and production at reasonable costs and
risks. However, it should be expected
that successful results will occur unevenly for both the drilling and Calliope
projects. Drilling results are dependent
on both the timing of drilling and on the drilling success rate. Calliope results are primarily dependent on
the timing, volume and quality of Calliope installations available to the
company.
The company will continue to actively pursue
adding reserves through its two core projects in fiscal 2008, and expects these
activities to be a reliable source of reserve additions. However, the timing and extent of such
activities can be dependent on many factors which are beyond the companys
control, including but not limited to, the availability, cost and quality of
oil field services such as drilling rigs, production equipment and related
services, and access to wells for application of the companys patented gas
recovery system on low pressure gas wells.
The prevailing price of oil and natural gas has a significant effect on
demand and, thus, the related cost of such services and wells.
The cost of field services, particularly the
cost of drilling wells, has increased dramatically during the past several years,
driven by higher energy prices.
Concurrently, the quality of field services has diminished markedly due
to manpower shortages. The combination
of much higher field service costs and degradation in the quality of the
services is having a material negative impact on drilling economics. Accordingly, the company continues to
high-grade its drilling prospects, and in some cases postpone less robust
projects pending improvement in the field services sector. In the short term, this will reduce the
number of drilling prospects which may, in turn, impede the growth of the
companys production and reserves.
The company is currently experiencing delays
in securing drilling rigs and delivery of production equipment, primarily
compressors and coil tubing. These
delays are extending the time it takes the company to conduct its field
operations. As a result, the company
could be at risk for price increases related to these types of services and
equipment.
All of the companys oil and natural gas
properties are located on-shore in the continental United States. The companys future drilling activities may
not be successful, and its overall drilling success rate may change. Unsuccessful drilling activities could have a
material adverse effect on the companys results of operations and financial
condition. Also, the company may not be
able to obtain the right to drill in areas where it believes there is
significant potential for the company.
12
Drilling Activities.
Northern Anadarko Basin
The company owns a
significant inventory of acreage (approximately 70,000 gross acres)
located along the northern portion of the Anadarko Basin where it conducts an
active drilling program. Wells generally
target the Morrow, Oswego and Chester formations between 7,000 and 11,000
feet. The company expects to drill a
substantial number of additional wells on this acreage.
In Hemphill County, Texas, the 11,200-foot wildcat
well drilled in fiscal 2007 to test the 3,780 gross acre Humphreys Prospect
encountered excellent quality Morrow sands, and tested at the rate of
3.0 MMcf per day. However,
production declined rapidly but stabilized at 150 Mcf per day. The stabilized production rate suggests that
the first well is indirectly connected to a larger Morrow reservoir. The company subsequently purchased and
reprocessed 3-D seismic over the prospect, and believes that it has identified
the primary Morrow channel. A second
well was drilled in January 2008 to test the seismic interpretation. That well encountered Tonkawa and Cherokee
sands that appear to be productive based on drilling data and electric logs,
but it did not encounter the high potential Morrow sands. The well is currently awaiting completion for
production. The company owns a 25%
working interest. Additional drilling is
expected on the prospect.
In Canadian County, Oklahoma, the 640 gross acre Loosen Prospect
continues to yield excellent drilling results from the Redfork and Skinner
formations. The 11,500-foot Marcia #1-14
was recently drilled and encountered Skinner and Mississippi sands. The well is currently awaiting completion and
pipeline connection. The Marcia well is
a north extension to the recently completed Chappell well which encountered pay
zones in five separate formations. The
well is currently completed in three of the five zones and is producing 1.9
MMcf and 30 barrels of oil per day.
The remaining zones will be opened for production at a later date. The Chappell well was a north extension to the
Hazel well, drilled in December 2006, which is still producing 2.0 MMcf
(million cubic feet of gas) and about 20 barrels of oil per day.
The company owns working interests in the new wells as follows: Hazel - 6.25%; Chappell - 16.3%,
Marcia - 14.5%.
In Harper County, Oklahoma, the 3,840 gross acre
Buffalo Creek Prospect continues to be a very active drilling area for the
company based on a recently completed 3-D seismic program. Nine wells have now been completed on the
prospect with production from the Chester, Morrow and Oswego formations. The most recent well encountered 14 feet of
excellent Morrow sand porosity, however, production testing has indicated that
the reservoir is extremely limited in size.
The company owns working interests in the prospect ranging from 31% to
37%. Three to five new drilling
locations are currently planned for 2008, and more are expected based on the
results of future wells.
In Ellis County, Oklahoma, the first well was
drilled on the companys 3,200 gross acre North Boxer Prospect. The 8,500-foot well is currently classified
as a tight hole, meaning information is not being released for proprietary
business reasons. A second wildcat well
drilled about one mile to the south was completed but produced water from the
objective sand. Two additional wells are
currently being readied for drilling.
The company owns working interests in the prospect ranging from 30% to
40%.
In Kingfisher County, Oklahoma, the first two wells
have been drilled on the 1,280 gross acre Okarche Prospect to test the
Hunton, Meramec, Chester and Redfork formations. The wells are each currently producing 200
Mcf and 10 barrels of oil per day. The
company owns working interests ranging from 9.5% to 11%.
In Carter County, Oklahoma,
the Southeast Hewitt Deese Sand Waterflood Unit has produced over
600,000 incremental barrels of oil, and continues to significantly
outperform initial expectations. As a
result of development drilling, production from the unit has recently
increased about 40% to 270 barrels of oil per day. Further development is under
consideration. The company owns a
17% working interest.
13
In Love County, Oklahoma, a new Deese sand
waterflood project is currently in the approval process. The company owns a 10% to 12% working
interest in various phases of the project.
South Texas
The companys
South Texas drilling projects diversify it exploration geographically,
scientifically, and in terms of capital, risk and reserve potential. Compared to the companys Oklahoma drilling,
the South Texas project involves higher costs and greater risks but offers
significantly higher per well production and reserve potential.
The most significant of the companys two South Texas projects is 3-D
seismic driven and focuses on the Vicksburg, Frio and Queen City sands in
Hidalgo County and the Wilcox sands in Jim Hogg County at depths ranging from
7,200 feet to 17,500 feet. To date, the
company has invested approximately $1,900,000 (net) in the project,
exclusive of drilling. Prior to sale or
farmout of the prospects, the company owns a 75% interest before recovery of
its investment, exclusive of drilling, and 37.5% thereafter. The company has the option to participate in
drilling any of the prospects for its full interest or to reduce its costs and
risks by selling or farming-out its interest to third parties in return for
cash consideration and a carried interest on the initial wildcat well(s).
The primary objective of
this project has been identification, leasing and sale of three deep Wilcox
prospects located in Jim Hogg County.
The prospects cover about 3,600
gross acres, range in depth from 16,500 to 17,500 feet, and are located
in an area where several nearby fields have produced hundreds of billions of
cubic feet of gas from the Wilcox formation.
The companys 3-D seismic interpretation indicates that the prospects are large enough in size to have
very substantial production and reserve potential in relation to the companys
existing production and reserves.
However, the prospects are high risk, rank wildcat prospects and per
well drilling costs far exceed those normally incurred by the company.
Therefore, the company has elected to sell a portion of its interest for cash
consideration and a carried interest on two initial wildcat wells. Third parties have committed to purchase the
three prospects and to drill a wildcat well on one prospect. The second wildcat well is optional based on
the outcome of the first well. Paperwork
is in the process of being completed.
The Operator has indicated the intent to commence drilling early in
2008. In addition to recovering a
significant portion its cash investment in the project and being carried for
an interest in the initial test well(s), the company has preserved its option
to participate in other wells drilled on the prospects with interests ranging
from 11.25% before recovery of its investment to 5.625% after
recovery. If drilling is
successful, the company expects that
its retained interest in the prospects will have a very significant impact
on its production and reserve growth.
Elsewhere in South Texas, the first well has been drilled on the 2,500
gross acre Briggs Ranch Prospect located in Victoria County. The prospect is fault separated from the
Heyser Field which has produced 738,000 barrels of oil and 17 Bcf from the Frio
sands. The 8,600-foot Briggs Ranch #1
encountered 11 feet of Frio sands and is currently producing about 1.0
MMcf per day. The company owns a
9% working interest.
North-Central Kansas
The companys Central Kansas drilling project
provides additional diversification to the companys drilling program through
the use of 3-D seismic to identify shallow oil prospects. The acreage is located in prolific oil
producing areas where 3-D seismic has proven effective in identifying satellite
structures near mature producing fields.
Higher oil prices have justified using 3-D seismic technology to
locate undrilled structures that are very difficult to find with old
technology. Drilling targets the
Lansing-Kansas City and Arbuckle formations at about 4,000 feet and,
compared to the companys Northern Anadarko Basin and South Texas projects, is
relatively low cost, low risk, and exclusively targets oil reserves in an
effort to bring better product balance to the companys reserve base. Thus far, the company has assembled four
separate drilling projects which encompass about 41,000 gross acres and is
continuing to seek opportunities to increase its exposure to the play. The company owns working interests in the
existing prospects ranging from 12.5% to 75%.
14
The companys recent
drilling results have improved dramatically as it continues to find the keys to
successful seismic and geologic interpretation.
Four of the last seven wells have been completed as producers, and three
of those appear to be outstanding wells.
In Graham County, two of the first three
wells on the 3,280 gross acre White Anticline and Mt. Vernon prospects resulted
in Lansing Kansas City formation discoveries.
Five
additional wells have been approved for drilling. The company owns a 12.5% working interest in
both prospects.
In Rawlins County, seismic is scheduled to
commence shortly on the companys 3,560 gross acre Beaver Jenks
prospect. The company owns a 30% working
interest in the prospect.
In Sheridan County, three of the last six
wells have resulted in discoveries on the companys 8,000 gross acre
Lucerne Prospect. Three additional wells
have been approved for drilling. The
company owns a 30% working interest in the prospect.
In Barton and Rice Counties, seismic is
scheduled to commence shortly on the companys 7,000 net acre prospect. The company owns a 75% working interest in
the prospect.
Calliope Gas Recovery
Technology
The company owns the exclusive right to a patented
technology known as the Calliope Gas Recovery System. There are currently three U.S. patents and
two Canadian patents related to the technology.
One additional patent that mirrors the U.S. patents has been
applied for in Canada. Calliope systems
are installed on wells located in Oklahoma, Texas and Louisiana.
Calliope can achieve
substantially lower flowing bottom-hole pressure than other production methods because
it does not rely on reservoir pressure to lift liquids. In many reservoirs, lower bottom-hole
pressure can translate into recovery of substantial additional natural gas
reserves.
Calliope has proven to be reliable and
flexible over a wide range of applications on wells the company owns and
operates. It has also proven to be
consistently successful. Accordingly,
the company is implementing strategies designed to expand the population of
wells on which it can install Calliope.
Calliopes Track Record
Calliope wells are located in Oklahoma,
Texas, and Louisiana and produce from both sandstone and carbonate reservoirs,
including the Chester, Cotton Valley, Edwards, Hart, Hunton, Morrow, Nodosaria,
Redfork and Springer formations. The
Calliope wells range in depth from 6,400 to 18,400 feet. These wells represent rigorous applications
for Calliope because at the time Calliope was installed, 14 of the wells
were dead (an average of two to three years), nine were uneconomic and two
were marginal. In addition, prior to the
time Calliope was installed, many of the reservoirs were damaged by the parting
shots of previous operators.
Twenty-three of the wells were acquired from other operators after
the operators had given-up on these wells.
The previous operators were mostly medium to large independent
oil and gas companies.
Initial Calliope production rates range up to
650 Mcfd and average per well Calliope reserves for non-experimental wells
are estimated to be 1.0 Bcf. One of the
companys early Calliope installations, the J.C. Carroll well, has now produced
over a billion cubic feet of gas using Calliope.
The 25 Calliope installed applications are
grouped into two categories experimental wells and non-experimental wells,
also referred to as go-forward applications.
Eleven of the 25 wells are experimental applications and
14 are go-forward applications.
Experimental wells generally represent the first experimental application
of a Calliope configuration in a wellbore.
For example, the first installation of Calliope inside a particular
tubing size is classified as an experimental application.
15
Calliope has achieved compelling results on
these less than ideal wells as is shown in the table below. For example, the entire group of 14
non-experimental wells were producing a total of only 88 Mcfd when Calliope was
installed. Without Calliope, the wells
represented a substantial plugging liability.
However, with Calliope, those same 14 wells have now produced an
incremental 3.4 Bcfe to date, and they are still producing about
2.0 MMcfed. With Calliope, the 14
wells were projected to have estimated ultimate incremental Calliope reserves
totaling 13.6 Bcfe.
|
|
|
|
Average
|
|
Total
|
|
Total
|
|
|
|
|
|
Calliope
|
|
Calliope
|
|
Projected
|
|
|
|
|
|
Reserves
|
|
Production
|
|
Calliope
|
|
|
|
No. of
|
|
Per Well
|
|
to Date
|
|
Reserves
|
|
Group
|
|
Wells
|
|
(Bcfe)
|
|
(Bcfe)
|
|
(Bcfe)
|
|
|
|
|
|
|
|
|
|
|
|
Non-Experimental
Wells
|
|
14
|
|
1.0
|
|
3.4
|
|
13.6
|
|
|
|
|
|
|
|
|
|
|
|
Experimental
Wells
|
|
11
|
|
0.2
|
|
0.6
|
|
1.4
|
|
|
|
|
|
|
|
|
|
|
|
All Wells
|
|
25
|
|
0.6
|
|
4.0
|
|
15.0
|
|
Calliope has proven to be a low risk and low
cost liquid lift technology. Calliope
has never failed to lift the liquids out of a wellbore. The average cost of a Calliope system is
$400,000 for a 12,000-foot application.
Based on average per well Calliope reserves of 1.0 Bcfe for go-forward
applications, cost of Calliope in terms of units of natural gas reserves added
is low compared to industry averages.
Based on current natural gas prices, Calliope can economically be
installed on wells which will yield significantly less than 1.0 Bcf of
Calliope reserves. This will enable the
company to significantly expand the range of Calliope applications to include
many low permeability reservoirs, possibly including those in shale and other resource
plays.
Realizing Calliopes value continues to be
one of the companys top priorities. The
company has been focused on three fronts to increase the number of Calliope
installations: expanding the geographic
region for purchasing Calliope candidate wells from third parties, joint
ventures with larger companies, and drilling wells into low-pressure gas
reservoirs for the purpose of using Calliope to recover stranded natural gas
reserves.
Purchasing Calliope Candidate
Wells
Calliope
operations were expanded into Texas and Louisiana in fiscal 2006. The company considers Texas and Louisiana to
be very fertile areas for Calliope and has retained personnel and opened a
Houston office to focus exclusively on purchasing wells for Calliope and on
Calliope joint ventures.
In general, higher natural gas prices have made it increasingly
difficult for the company to purchase wells for its Calliope system. In addition, higher gas prices have provided
the incentive for other companies to perform high risk procedures (parting
shots) in an attempt to revive wells prior to abandoning or selling the
wells. These parting shots often result
in severe reservoir damage that renders wells unsuitable for Calliope. Accordingly, viable Calliope candidate wells
available to be purchased by the company have been very restricted.
Joint Ventures With Third Parties
In an effort to increase the number of
Calliope installations, the company has been discussing joint ventures
with larger companies. Presentations
have been made to a select group of companies, including majors and large
independents. All of the companies have
expressed an interest in Calliope. Two
joint venture agreements were completed during 2007. Another joint venture agreement was completed
in the first quarter of 2008. Joint
venture discussions are in progress with a number of the companies, including
evaluation of candidate wells.
16
The joint venture negotiation process has taken longer than expected
because there are many decision points within large companies that cause
delays. Nevertheless, the company
continues to dedicate substantial resources to joint venture projects, as it
believes that the company will eventually be successful in the joint venture
area.
Calliope
Drilling Project
The company believes that there is a huge amount
of gas stranded in abandoned and low pressure reservoirs that can be recovered
using Calliope. It believes drilling new
wells for Calliope into such reservoirs will provide a repeatable opportunity
to lease large areas for systematic re-development. In addition, new wells allow optimum casing
and tubular sizes to be installed which will substantially improve reserves and
production compared to installing Calliope on existing wells where undersized
tubulars often restrict Calliopes optimum performance.
In June 2007, the company entered into a
joint venture to purchase an 11,000-foot well located in East Texas. The previous operator drilled the well and
encountered low reservoir pressure.
After unsuccessful attempts to make the well produce, the operator sold
the well to the company joint venture for $65,000 (salvage value). Calliope was installed and immediately
brought the well to life, producing at the rate of 250 Mcf per day. The well provided a successful test of the
Calliope drilling concept and demonstrated that Calliope will successfully
solve liquid loading problems that are difficult, if not impossible, to address
with other liquid lift technologies.
Results of Operations
Three Months Ended January 31,
2008 Compared to Three Months Ended January 31, 2007
For the three months ended January 31,
2008, total revenues grew 13% to $4,575,000 compared to $4,055,000 during the
same period last year. As the oil and
gas price/volume table on page 12 shows, total gas price realizations,
which reflect hedging transactions, increased 37% to $8.24 per Mcf and oil
price realizations increased 66% to $86.39 per barrel. The net effect of these price changes was to
increase oil and gas sales by $1,282,000.
For the three months ended January 31, 2008, the companys gas
equivalent production fell 19% resulting in an oil and gas sales decrease of
$510,000. Investment and other income
decreased $252,000 primarily due to performance of the companys
investments, compared to last year.
For the three months ended January 31,
2008, total costs and expenses fell 5% to $2,038,000 compared to $2,155,000 for
the comparable period in 2007. Oil and
gas production expenses fell due primarily to a decrease in production taxes
and a decrease in lease operating expenses related to several major workovers
in 2007. DD&A declined primarily due
to lower production partially offset by an increase in the amortizable cost
base. General and administrative
expenses increased primarily due to accounting and professional fees. Interest expense relates to the exclusive
license agreement note payment. The effective tax rate was 29.0% and 28.2% for
the 2008 and 2007 periods, respectively.
SIGNIFICANT ACCOUNTING POLICIES
The company believes the following accounting
policies and estimates are critical in the preparation of its consolidated
financial statements: the carrying value of its oil and natural gas properties,
the accounting for oil and gas reserves, and the estimate of its asset
retirement obligations.
OIL AND GAS PROPERTIES.
The
company uses the full cost method of accounting for costs related to its oil
and natural gas properties. Capitalized
costs included in the full cost pool are depleted on an aggregate basis using
the units-of-production method.
Depreciation, depletion and amortization is a significant component of
oil and natural gas properties. A change
in proved reserves without a corresponding change in capitalized costs will
cause the depletion rate to increase or decrease.
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Both the volume of proved reserves and any
estimated future expenditures used for the depletion calculation are based on
estimates such as those described under Oil and Gas Reserves below.
The capitalized costs in the full cost pool
are subject to a quarterly ceiling test that limits such pooled costs to the
aggregate of the present value of future net revenues attributable to proved
oil and natural gas reserves discounted at 10 percent plus the lower of cost or
market value of unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling,
the company will record a write-down to the extent of such excess as a non-cash
charge to earnings. Any such write-down
will reduce earnings in the period of occurrence and result in lower
depreciation and depletion in future periods.
A write-down may not be reversed in future periods, even though higher
oil and natural gas prices may subsequently increase the ceiling.
The company has made only one ceiling
write-down in its 28-year history. That
write down was made in 1986 after oil prices fell 51% and natural gas
prices fell 45% between fiscal year end 1985 and 1986.
Changes in oil and natural gas prices have
historically had the most significant impact on the companys ceiling
test. In general, the ceiling is lower
when prices are lower. Even though oil
and natural gas prices can be highly volatile over weeks and even days, the
ceiling calculation dictates that prices in effect as of the last day of the
test period be used and held constant.
The resulting valuation is a snapshot as of that day and, thus, is generally
not indicative of a true fair value that would be placed on the companys
reserves by the company or by an independent third party. Therefore, the future net revenues associated
with the estimated proved reserves are not based on the companys assessment of
future prices or costs, but rather are based on prices and costs in effect as
of the end the test period.
OIL AND GAS RESERVES.
The determination of depreciation and depletion expense as well as
ceiling test write-downs related to the recorded value of the companys oil and
natural gas properties are highly dependent on the estimates of the proved oil
and natural gas reserves. Oil and
natural gas reserves include proved reserves that represent estimated
quantities of crude oil and natural gas which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in
estimating oil and natural gas reserves and their values, including many
factors beyond the companys control.
Accordingly, reserve estimates are often different from the quantities
of oil and natural gas ultimately recovered and the corresponding lifting costs
associated with the recovery of these reserves.
ASSET RETIREMENT
OBLIGATIONS.
The company estimates the future cost of
asset retirement obligations, discounts that cost to its present value, and
records a corresponding asset and liability in its Consolidated Balance
Sheets. The values ultimately derived
are based on many significant estimates, including future abandonment costs,
inflation, market risk premiums, useful life, and cost of capital. The nature of these estimates requires the
company to make judgments based on historical experience and future
expectations. Revisions to the estimates
may be required based on such things as changes to cost estimates or the timing
of future cash outlays. Any such changes
that result in upward or downward revisions in the estimated obligation will
result in an adjustment to the related capitalized asset and corresponding
liability on a prospective basis.
REVENUE RECOGNITION
.
The company derives its revenue primarily
from the sale of produced natural gas and crude oil. The company reports revenue gross for the
amounts received before taking into account production taxes and transportation
costs which are reported as oil and gas production expenses. Revenue is recorded in the month production
is delivered to the purchaser at which time title changes hands. The company makes estimates of the amount of
production delivered to purchasers and the prices it will receive. The company uses its knowledge of its
properties, their historical performance, the anticipated effect of weather
conditions during the month of production, NYMEX and local spot market prices,
and other factors as the basis for these estimates. Variances between estimates and the actual
amounts received are recorded when payment is received.
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A majority of the companys sales are made
under contractual arrangements with terms that are considered to be usual and
customary in the oil and gas industry.
The contracts are for periods of up to five years with prices determined
based upon a percentage of a pre-determined and published monthly index
price. The terms of these contracts have
not had an effect on how the company recognizes its revenue.
ITEM 3.
QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK
The company manages exposure to commodity
price fluctuations by periodically hedging a portion of expected production
through the use of derivatives, typically collars and forward short positions
in the NYMEX or other regional indexes futures market. See Note 4 for more information on the
companys hedging activities.
ITEM 4.
CONTROLS AND PROCEDURES
Evaluation
of Disclosure Controls and Procedures
Our management evaluated,
with the participation and under the supervision of our Chief Executive Officer
and Chief Financial Officer, the effectiveness of our disclosure controls and
procedures as of the end of the period covered by this Quarterly Report on Form
10-Q. Based on this evaluation, our Chief Executive Officer and our Chief
Financial Officer concluded that our disclosure controls and procedures are effective
to ensure that information we are required to disclose in reports that we file
or submit under the Securities Exchange Act of 1934 is accumulated and
communicated to our management, including our Chief Executive Officer and our
Chief Financial Officer, as appropriate to allow timely decisions regarding
required disclosure and that such information is recorded, processed,
summarized and reported within the time periods specified in Securities and
Exchange Commission rules and forms.
Changes in Internal Control Over
Financial Reporting
There has been no change in our internal control over financial
reporting that occurred during our last fiscal quarter that has materially
affected or is reasonably likely to materially affect our internal control over
financial reporting, except as follows: In Item 9A, Managements Report on
Internal Control over Financial Reporting included in our Annual Report on
Form 10-K for the year ended October 31, 2007 we reported a material weakness
in the companys internal control. During the first quarter of fiscal
2008 management designed and implemented enhanced and accelerated training
for its senior financial staff and hired an expert consultant to assist with
review and financial statement disclosure. Management has not completed
all of the testing of internal controls in these areas for fiscal 2008.
PART II - OTHER INFORMATION
ITEM 1.
LEGAL
PROCEEDINGS
None.
ITEM 1A.
RISK
FACTORS
There have been no material changes from the risk
factors previously disclosed in the companys Annual Report on Form 10-K
for the fiscal year ended October 31, 2007.
ITEM 2.
UNREGISTERED
SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
19
ITEM 3.
DEFAULTS
UPON SENIOR SECURITIES
None.
ITEM 4.
SUBMISSION
OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
ITEM 5.
OTHER
INFORMATION
None.
ITEM 6.
EXHIBITS
Exhibits are as
follow:
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31.1
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Certification by Chief Executive Officer under
Section 302 of the Sarbanes-Oxley Act of 2002
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31.2
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Certification by Chief Financial Officer under
Section 302 of the Sarbanes-Oxley Act of 2002
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32.1
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Certification by Chief Executive Officer and Chief
Financial Officer under Section 906 of the Sarbanes-Oxley Act
(18 U.S.C. Section 1350)
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
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CREDO Petroleum Corporation
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(Registrant)
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By:
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/s/ James T. Huffman
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James T. Huffman
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President and Chief Executive Officer
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(Principal Executive Officer)
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By:
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/s/ David E. Dennis
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David E. Dennis
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Chief Financial Officer
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(Principal Financial and Accounting Officer)
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Date: March 10, 2008
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