RILEY EXPLORATION PERMIAN, INC.
10-Ks and 10-Qs
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UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
WASHINGTON,
D.C. 20549
REPORT
ON FORM 10-K
(Mark
one)
[X}
Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934 for the fiscal year ended
December 31, 2009
or
[ ]
Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act
of 1934 for the transition period from __________ to __________.
Commission
File No. 1-15555
TENGASCO,
INC
.
(name of
registrant as specified in its charter)
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Tennessee
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87-0267438
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(state
or other jurisdiction of
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(I.R.S.
Employer
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Incorporation
or organization)
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Identification
No.)
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11121
Kingston Pike Suite, E
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Knoxville,
TN 37934
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(Address
of Principal Executive Offices)
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(Zip
Code)
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Registrant’s
telephone number, including area code:
(865) 675-1554
Securities
registered pursuant to Section 12(b) of the Act:
None.
Securities
registered pursuant to Section 12(g) of the Act:
Common Stock, $.001 par value per
share.
Indicate by check mark if the
registrant is a well-known seasoned issuer, as defined by Rule 405 of the
Securities Act. Yes [ ] [
X]
No
Indicate by check mark if the
registrant is not required to file reports pursuant to Section 13 or Section
15(d) of the Act. Yes [ ] [
X]
No
Indicated by check mark whether the
registrant (1) 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 [
X
] [
]
No
Indicate by checkmark whether the
registrant has submitted electronically and posted on its corporate website, if
any, every Interactive Data File required to be submitted and posted pursuant to
Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12
months (or for such shorter period that the registrant was required to submit
and post such files [ ] Yes [ ] No
Indicate by check mark if disclosure of
delinquent filers in response to Item 405 of Regulation SK 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, a non-accelerated
filer or smaller reporting company. See definitions of “large accelerated
filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act. Large Accelerated Filer [ ] Accelerated Filer
[ ] Non-accelerated Filer [ ] Smaller
Reporting Company [ ]
(Do not check if a Smaller Reporting
Company)
Indicate by checkmark whether the
registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [ ] No [
X]
The aggregate market value of the
voting and non-voting common equity held by non-affiliates computed by reference
to the price at which the common equity was last sold, or the average bid and
asked price of such common equity, as of the last business day of the
registrant’s most recently completed second fiscal quarter was approximately $21
million (June 30, 2009 closing price $0.56)
The number of shares outstanding of the
registrant’s $.001 par value common stock as of the close of business on (March
12, 2010) was 59,760,661
Documents
Incorporated By Reference
The information required by Part III of
the Form 10-K, to the extent not set forth herein, is incorporated herein by
reference from the registrant’s definitive proxy statement for the Annual
Meeting of Shareholders to be held on June 21, 2010, to be filed with the
Securities and Exchange Commission pursuant to Regulation 14A not later than 120
days after the close of the registrant’s fiscal year
.
Table
of Contents
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PART
I
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Page
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Item
1.
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Business……………………………………………………………..
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5
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Item
1A.
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Risk
Factors…………………………………………………………
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21
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Item
1B.
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Unresolved
Staff Comments….…………..…………………….......
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31
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Item
2.
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Properties……………………………………………………………
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31
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Item
3.
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Legal
Proceedings……………………………………..……....…....
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39
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Item
4.
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(Removed
and Reserved)…………………………………………...
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39
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PART
II
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Item
5.
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Market
for Registrant’s Common Equity, Related Stockholder
Matters
and Issuer Purchases of Equity Securities………………...
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39
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Item
6.
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Selected
Financial Data…………………………………………….
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41
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Item
7.
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Management’s
Discussion and Analysis of Financial Condition
and
Results of Operation……………………………………….….
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42
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Item
7A.
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Quantitative
and Qualitative Disclosures About Market Risk…….
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49
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Item
8.
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Financial
Statements and Supplementary Data…….……………...
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51
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Item
9.
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Changes
in and Disagreements With Accountants on Accounting
and
Financial Disclosure………………………………………….
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51
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Item
9A(T).
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Controls
and Procedures………………………………………….
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51
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Item
9B.
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Other
Information………..………………………………………..
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52
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PART
III
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Item
10.
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Directors,
Executive Officers and Corporate Governance………..
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53
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Item
11.
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Executive
Compensation………………………………………….
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53
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Item
12.
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Security
Ownership of Certain Beneficial Owners and Management and Related
Stockholders Matters….……………………………..
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53
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Item
13.
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Certain
Relationships and Related Transactions, and Director
Independence………..…………………………………………….
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54
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Item
14.
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Principal
Accounting Fees and Service…………………………...
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54
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PART
IV
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Item
15.
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Exhibits,
Financial Statement and Schedules……………………..
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55
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SIGNATURES
……………………………………..……………
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58
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FORWARD LOOKING
STATEMENTS
The information contained in this
Report, in certain instances, includes forward-looking statements within the
meaning of applicable securities laws. Forward-looking statements
include statements regarding the Company’s “expectations,” “anticipations,”
“intentions,” “beliefs,” or “strategies” or any similar word or phrase regarding
the future. Forward-looking statements also include statements
regarding revenue margins, expenses, and earnings analysis for 2009 and
thereafter; oil and gas prices; exploration activities; development
expenditures; costs of regulatory compliance; environmental matters;
technological developments; future products or product development; the
Company’s products and distribution development strategies; potential
acquisitions or strategic alliances; liquidity and anticipated cash needs and
availability; prospects for success of capital raising activities; prospects or
the market for or price of the Company’s common stock; and control of the
Company. All forward-looking statements are based on information
available to the Company as of the date hereof, and the Company assumes no
obligation to update any such forward-looking statement. The
Company’s actual results could differ materially from the forward-looking
statements. Among the factors that could cause results to differ materially are
the factors discussed in “Risk Factors” below in Item 1A of this
Report.
Projecting the effects of commodity
prices, which in the past year have been extremely volatile, on production and
timing of development expenditures includes many factors beyond the Company’s
control. The future estimates of net cash flows from the Company’s
proved reserves and their present value are based upon various assumptions about
future production levels, prices, and costs that may prove to be incorrect over
time. Any significant variance from assumptions could result in the
actual future net cash flows being materially different from the
estimates.
GLOSSARY
OF OIL AND GAS TERMS
The
following are abbreviations and definitions of certain terms commonly used in
the oil and gas industry and this document:
Bbl.
One
stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or
other liquid hydrocarbons.
Bcf.
One
billion cubic feet of gas.
BOE
. One
stock tank barrel equivalent of oil, calculated by converting gas volumes to
equivalent oil barrels at a ratio of 6 thousand cubic feet of gas to 1 barrel of
oil.
BOPD
.
Barrels of oil per day.
Btu.
British thermal unit. One British thermal unit is the amount of heat required to
raise the temperature of one pound of water by one degree
Fahrenheit.
Developed oil and
gas reserves
. Developed oil and gas reserves are reserves of any category
that can be expected to be recovered: (i) through existing wells with existing
equipment and operating methods or in which the cost of the required equipment
is relatively minor compared to the cost of a new well; and (ii)
1
through
installed extraction equipment and infrastructure operational at the time of the
reserves estimate if the extraction is by means not involving a
well.
Development
project
. A development project is the means by which petroleum resources
are brought to the status of economically producible. As examples, the
development of a single reservoir or field, an incremental development in a
producing field or the integrated development of a group of several fields and
associated facilities with a common ownership may constitute a development
project.
Development
well
. A well drilled within the proved area of an oil or gas reservoir to
the depth of a stratigraphic horizon known to be productive.
Differential
.
An adjustment to the price of oil or gas from an established spot market price
to reflect differences in the quality and/or location of oil or
gas.
Economically
producible
. The term economically producible, as it relates to a
resource, means a resource which generates revenue that exceeds, or is
reasonably expected to exceed, the costs of the operation. The value of the
products that generate revenue shall be determined at the terminal point of oil
and gas producing activities.
Estimated
ultimate recovery (EUR)
. Estimated ultimate recovery is the sum of
reserves remaining as of a given date and cumulative production as of that
date,
Exploratory
well
. A well drilled to find a new field or to find a new reservoir in a
field previously found to be productive of oil or gas in another reservoir.
Generally, an exploratory well is any well that is not a development well, an
extension well, a service well or a stratigraphic test well.
Farmout.
An assignment of an interest in a drilling location and related acreage
conditional upon the drilling of a well on that location.
Gas.
Natural gas.
MBbl.
One
thousand barrels of oil or other liquid hydrocarbons.
MBOE.
One
thousand BOE.
Mcf.
One
thousand cubic feet of gas.
Mcfd.
One
thousand cubic feet of gas per day
MMcfe.
One
million cubic feet of gas equivalent.
MMBOE.
One
million BOE.
MMBtu.
One
million British thermal units.
MMcf.
One
million cubic feet of gas.
NYMEX.
New
York Mercantile Exchange.
Oil.
Crude
oil, condensate and natural gas liquids.
2
Operator.
The individual or company responsible for the exploration and/or production of
an oil or gas well or lease.
Play.
A
geographic area with hydrocarbon potential.
Proved oil and
gas reserves.
Proved oil and gas reserves are those quantities of oil and
gas, which, by analysis of geoscience and engineering data, can be estimated
with reasonable certainty to be economically producible from a given date
forward, from known reservoirs, and under existing economic conditions,
operating methods, and government regulations prior to the time at which
contracts providing the right to operate expire, unless evidence indicates that
renewal is reasonably certain, regardless of whether deterministic or
probabilistic methods are used for estimation. The project to extract the
hydrocarbons must have commenced, or the operator must be reasonably certain
that it will commence the project, within a reasonable time.
The area
of the reservoir considered as proved includes all of the following
:
(i)
the area identified by drilling and limited by fluid contacts, if any; and (ii)
adjacent undrilled portions of the reservoir that can, with reasonable
certainty, be judged to be continuous with it and to contain economically
producible oil and gas on the basis of available geoscience and engineering
data.
In the
absence of data on fluid contacts, proved quantities in a reservoir are limited
by the lowest known hydrocarbons as seen in a well penetration unless
geoscience, engineering or performance data and reliable technology establish a
lower contact with reasonable certainty.
Where
direct observation from well penetrations has defined a highest known oil
elevation and the potential exists for an associated gas cap, proved oil
reserves may be assigned in the structurally higher portions of the reservoir
only if geoscience, engineering or performance data and reliable technology
establish the higher contact with reasonable certainty.
Reserves
which can be produced economically through application of improved recovery
techniques (including, but not limited to, fluid injection) are included in the
proved classification when: (i) successful testing by a pilot project in an area
of the reservoir with properties no more favorable than in the reservoir as a
whole, the operation of an installed program in the reservoir or an analogous
reservoir or other evidence using reliable technology establishes the reasonable
certainty of the engineering analysis on which the project or program was based;
and (ii) the project has been approved for development by all necessary parties
and entities, including governmental entities.
Existing
economic conditions include prices and costs at which economic producibility
from a reservoir is to be determined. The price shall be the average price
during the twelve-month period prior to the ending date of the period covered by
the report, determined as an unweighted arithmetic average of the
first-day-of-the-month price for each month within such period, unless prices
are defined by contractual arrangements, excluding escalations based upon future
conditions.
Proved reserve
additions.
The sum of additions to proved reserves from extensions,
discoveries, improved recovery, acquisitions and revisions of previous
estimates.
Reserves.
Reserves are estimated remaining quantities of oil and gas and related
substances anticipated to be economically producible, as of a given date, by
application of development projects to known
3
accumulations.
In addition, there must exist, or there must be a reasonable expectation that
there will exist, the legal right to produce or a revenue interest in the
production, installed means of delivering oil and gas or related substances to
market and all permits and financing required to implement the project. Reserves
should not be assigned to adjacent reservoirs isolated by major, potentially
sealing, faults until those reservoirs are penetrated and evaluated as
economically producible. Reserves should not be assigned to areas that are
clearly separated from a known accumulation by a non-productive reservoir (i.e.,
absence of reservoir, structurally low reservoir or negative test results). Such
areas may contain prospective resources (i.e., potentially recoverable resources
from undiscovered accumulations).
Reserve
additions.
Changes in proved reserves due to revisions of previous
estimates, extensions, discoveries, improved recovery and other additions and
purchases of reserves in-place.
Reserve
life.
A measure of the productive life of an oil and gas property or a
group of properties, expressed in years.
Royalty
interest.
An interest in an oil and gas lease that gives the owner of the
interest the right to receive a portion of the production from the leased
acreage (or of the proceeds of the sale thereof), but generally does not require
the owner to pay any portion of the costs of drilling or operating the wells on
the leased acreage. Royalties may be either landowner's royalties, which are
reserved by the owner of the leased acreage at the time the lease is granted, or
overriding royalties, which are usually reserved by an owner of the leasehold in
connection with a transfer to a subsequent owner.
Standardized
measure.
The present value, discounted at 10% per year, of estimated
future net revenues from the production of proved reserves, computed by applying
sales prices used in estimating proved oil and gas reserves to the year-end
quantities of those reserves in effect as of the dates of such estimates and
held constant throughout the productive life of the reserves and deducting the
estimated future costs to be incurred in developing, producing and abandoning
the proved reserves (computed based on year-end costs and assuming continuation
of existing economic conditions). Future income taxes are calculated by applying
the appropriate year-end statutory federal and state income tax rate with
consideration of future tax rates already legislated, to pre-tax future net cash
flows, net of the tax basis of the properties involved and utilization of
available tax carryforwards related to proved oil and gas reserves.
SWD.
Salt
water disposal well
Undeveloped oil
and gas reserves.
Undeveloped oil and gas reserves are reserves of any
category 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. Reserves on undrilled acreage shall be limited to those directly
offsetting development spacing areas that are reasonably certain of production
when drilled, unless evidence using reliable technology exists that establishes
reasonable certainty of economic producibility at greater distances. Undrilled
locations can be classified as having undeveloped reserves only if a development
plan has been adopted indicating that they are scheduled to be drilled within
five years, unless the specific circumstances justify a longer time. Under no
circumstances shall estimates for undeveloped reserves be attributable to any
acreage for which an application of fluid injection or other improved recovery
technique is contemplated, unless such techniques have been proved effective by
actual projects in the same reservoir or an analogous reservoir, or by other
evidence using reliable technology establishing reasonable
certainty.
4
Working
interest.
An interest in an oil and gas lease that gives the owner of the
interest the right to drill for and produce oil and gas on the leased acreage
and requires the owner to pay a share of the costs of drilling and production
operations.
References
herein to the “Company”, “we”, “us” and “our” mean Tengasco, Inc.
History
of the Company
The Company was initially organized in
Utah in 1916 under a name later changed to Onasco Companies, Inc. In
1995, the Company changed its name from Onasco Companies, Inc. by merging into
Tengasco, Inc., a Tennessee corporation, formed by the Company solely for this
purpose.
OVERVIEW
The
Company is in the business of exploration for and production of oil and natural
gas. The Company’s primary area of oil exploration and production is
in Kansas. The Company’s primary area of gas exploration and
production is the Swan Creek field in Tennessee.
The
Company’s wholly-owned subsidiary, Tengasco Pipeline Corporation (“TPC”) owns
and operates a 65-mile intrastate pipeline which it constructed to transport
natural gas from the Company’s Swan Creek Field to customers in Kingsport,
Tennessee.
The
Company’s wholly-owned subsidiary, Manufactured Methane Corporation (“MMC”) owns
and operates treatment and delivery facilities using the latest developments in
available treatment technologies for the extraction of methane gas from
nonconventional sources for delivery through the nation’s existing natural gas
pipeline system, including the Company’s TPC pipeline system in Tennessee for
eventual sale to natural gas customers.
The Company also has a management
agreement with Hoactzin Partners, L.P. (“Hoactzin”) to manage Hoactzin’s oil and
gas properties in the Gulf of Mexico offshore Texas and Louisiana. (See 4.
Management Agreement with Hoactzin on page 12) As consideration for that
agreement the Company obtained reimbursement from Hoactzin of a portion of
salary and expenses for the Company’s Vice President Patrick McInturff, as well
as an option to participate in production and exploration activities in
Hoactzin’s properties in those areas. Peter E. Salas, the Chairman of the Board
of Directors of the Company, is the controlling person of Hoactzin. He is also
the sole shareholder and controlling person of Dolphin Management, Inc., the
general partner of Dolphin Offshore Partners, L.P., which is the Company’s
largest shareholder.
5
General
1.
The Kansas Properties
The Kansas Properties presently include
184 producing oil wells in central Kansas. Our management and staff
have a great deal of Kansas exploration and production experience. We
have onsite production management and field personnel working in
Kansas.
On July 2, 2008, the Company acquired
19 leases encompassing approximately 1,577 acres and 41 oil wells producing
approximately 80 barrels of oil per day in Rooks County, Kansas together with
salt water disposal wells and related equipment from Black Diamond Oil, Inc. for
$5.35 million. The leases acquired are in the Company’s core area in
central Kansas and are a part of the larger Riffe Field. Polymer treatments on
several existing wells resulted in an increase in production of the
acquired wells to 147 BOPD by the end of 2008. Total production during the
initial six month ownership period was 22 MBbls, an average of 122
BOPD. In 2009, despite very little freshly deployed capital, these wells
averaged 111 BOPD.
In 2009, the decrease in oil prices,
particularly in the first 6 months of the year, prevented the Company from
having sufficient cash flow to remain as active in drilling new wells and
performing polymer treatments as we had been in prior years. We had
no capital spending until late 2009 and only drilled one salt water disposal
well for the 2008 Albers discovery wells which produced 21 MBbls in
2009. We also performed 2 polymer jobs late in 2009 which added 2.9
MBbls to our production total.
In 2009, the Company continued to try
to acquire key acreage and analyze seismic data to aid its exploration
and development program. While the Company intends in 2010 to
return to a more active drilling and workover program, the level of activity
will be driven by cash flow. Those expectations can be tempered with
a change in oil prices like we endured in late 2008 and early
2009. At the time of this writing, prices and our derivative position
will allow a more active plan for 2010.
A. Kansas Ten Well Drilling
Program
On September 17, 2007, the Company
entered into a ten well drilling program with Hoactzin, consisting of three
wildcat wells and seven developmental wells to be drilled on the Company’s
Kansas Properties (the “Program”). Under the terms of the Program, Hoactzin paid
the Company $400,000 for each producing well and $250,000 for each per dry
hole. The terms of the Program also provided that Hoactzin would
receive all the working interest in the producing wells, and would pay an
initial fee to the Company of 25% of its working interest revenues net of
operating expenses, referred to as a management fee. The fee paid to
the Company by Hoactzin will increase to 85% working interest when net revenues
received by Hoactzin reach an agreed payout point of approximately 1.35 times
Hoactzin’s purchase price (the “Payout Point”).
Nine of the ten wells in the program
were completed as oil producers and are currently producing approximately 61
barrels per day in total. Hoactzin paid a total of $3.85 million (the
“Purchase Price”) for its interest in the Program resulting in the Payout Point
being determined as $5.2 million. The Purchase Price paid by Hoactzin
for its interest in the Program wells exceeded the Company’s actual drilling
cost of approximately $2.6 million for the ten wells by more than $1
million.
6
In 2009, the wells from the Program
produced 22 MBbls of which 14 MBbls were net to Hoactzin. As of
December 31, 2009, net revenues received by Hoactzin from the Program total $2.5
million which leaves a balance of $2.7 million until the Payout Point is
reached.
Although production level of the
Program wells will decline over time in accordance with expected decline curves,
based on the drilling results of the Program wells to date and the current price
of oil, the Program wells are expected to reach the Payout Point in
approximately four years from first production. However, under the
terms of the agreement reaching the Payout Point could be accelerated by
applying 75% of the net proceeds Hoactzin receives from the methane extraction
project developed by MMC at the Carter Valley, Tennessee landfill (the “Methane
Project”), toward reaching the Payout Point. (The Methane
Project is discussed in greater detail below.) The Methane Project
net proceeds when applied would result in the Payout Point being achieved sooner
than the estimated four year period based solely upon revenues from the Program
wells.
On September 17, 2007, the Company
entered into another agreement with Hoactzin providing that if the Program and
the Methane Project in combination failed to return net revenues to Hoactzin
equal to 25% of the Purchase Price by December 31, 2009, then Hoactzin had an
option to exchange up to 20% of its net profits interest in the Methane Project
for convertible preferred stock to be issued by the Company with a liquidation
value equal to 20% of the Purchase Price less the net proceeds received at the
time of any exchange. The conversion option would be set at issuance
of the preferred stock at the then twenty business day trailing average closing
price of Company stock on the NYSE Amex. This option could not have
occurred at year-end 2009 because approximately 50% of the Purchase Price was
returned to Hoactzin from revenues from the wells in the Program by the end of
2008. Hoactzin has a similar option each year after 2010 in which
Hoactzin’s then-unrecovered Purchase Price at the beginning of the year is not
reduced 20% further by the end of that year, using the same conversion option
calculation. The Company, however, may in any year make cash payment
from any source in the amount required to prevent such an exchange option for
preferred stock from arising. In addition, the conversion right is
limited to a conversion of no more than 19% in the aggregate of the outstanding
common shares of the Company. In the event Hoactzin’s 75% net profits
interest in the Methane Project were fully exchanged for preferred stock
Hoactzin would retain no net profits interest in the Methane Project after the
full exchange.
Under this exchange agreement, if no
proceeds at all were received by Hoactzin through 2009 or in a later year (i.e.
a worst-case scenario already impossible in view of the success of the Program),
then Hoactzin would have an option to exchange 20% of its interest in the
Methane Project beginning in 2011 and each year thereafter for preferred stock
convertible at the trailing average price before each year’s issuance of the
preferred. The number of common shares into which the preferred stock
could be converted cannot be currently calculated, because the conversion price
is based on a future stock price.
However, as stated, net revenues
received by Hoactzin from the wells in the Program through December 31, 2009
totaled $2.5 million leaving a balance of $1.3 million to reach the point at
which no preferred stock can be issued to Hoactzin thus making it highly
unlikely that any preferred stock will ever be issued to
Hoactzin. The Company notes that with the demonstrated successful
results of production from the wells in the Program that the payout of 25% of
the Purchase Price was reached by year-end 2008, a full year before the December
31, 2009 required date, therefore no requirement to issue preferred
7
stock
will arise in 2010. The Company further anticipates that at current
prices of about $70.00 per barrel of oil and $6.00 per Mcf of gas, and at
currently expected sales levels of methane gas from the Methane Project that the
balance of the unrecovered Purchase Price by Hoactzin may be fully recovered by
Hoactzin by year-end 2011. If this occurs the possibility of being required to
issue any preferred ceases to exist. If it does not occur, the Company believes
it is highly unlikely that any obligation to issue preferred stock will arise
under the terms of this agreement at any time in the future, because the
production results in any future year should readily satisfy the small
production levels required to prevent an optional preferred stock issuance from
arising in any year.
B. Kansas
Production
The Company’s gross oil production in
Kansas decreased in 2009 from 2008 levels. In 2009, the Company produced 217
MBbls in Kansas compared to 232 MBbls in 2008. The two wells that were polymered
in 2009 produced 2.9 MBbl and the one new well drilled in 2009 was a salt water
disposal well (SWD) for the Albers lease.
Capital projects for the Company are
funded by cash flow and in 2009 the Company had reduced cash flow, especially in
the first 9 months of the year. We plan to be more active in 2010 as
current oil prices have increased. However, decreases in future oil
prices may cause the Company to reduce capital spending. In July 2009
the Company hedged a specified number of barrels of oil that currently
constitutes about two-thirds of the Company’s daily production to minimize this
effect.
2. The
Tennessee Properties
In the early 1980’s Amoco Production
Company owned numerous acres of oil and gas leases in the Eastern Overthrust in
the Appalachian Basin, including the area now referred to as the Swan Creek
Field. Amoco successfully drilled two natural gas discovery wells in
the Swan Creek Field to the Knox Formation. In the mid-1980’s,
however, development of this field was cost prohibitive due to a substantial
decline in worldwide oil and gas prices which was further exacerbated by the
high cost of constructing a necessary 23-mile pipeline to deliver gas from the
Swan Creek Field to the closest market. In July 1995, the Company acquired the
Swan Creek leases and began development of the field.
A. Swan Creek Pipeline
Facilities
The Company’s completed pipeline system
is owned and operated by Tengasco Pipeline Corporation (“TPC”), the Company’s
wholly-owned subsidiary and extends 65 miles from the Swan Creek Field to a
meter station at Eastman Chemical Company’s (“Eastman”) plant in Kingsport,
Tennessee. The pipeline system was built for a total cost of $16.4
million.
B. Swan Creek Production and
Development
The Company has concluded based on the
results of previously drilled wells and seismic data that drilling new gas wells
in the Swan Creek Field would not achieve any significant increase in daily gas
production totals from the Field. Current wells in production in the Swan Creek
Field would be capable of and would likely produce all the remaining reserves in
that Field. As a result, the Company has not drilled any new gas
wells in the Swan Creek Field since 2004.
8
Because no drilling for natural gas in
the Knox formation in Swan Creek is anticipated in the future, the current
production levels less decline are the sole value of natural gas reserves and
production. The existing production and the current 16 wells
producing natural gas are showing typical Appalachian production declines, which
exhibit a long-lived nature but more modest volumes. The experienced
decline in actual production levels from existing wells in the Swan Creek Field
from 2008 to 2009 was expected and predictable. Although there can be
no assurance, the Company expects these natural rates of decline in the future
will be comparable to the decline experienced over the 2008-2009
period.
During 2009, the Company had 17
producing gas wells and 4 producing oil wells in the Swan Creek
Field. Gas sales from the Swan Creek Field during 2009 averaged 124
Mcfd compared to 215 Mcfd in 2008.
In January 2008, the Company signed a
farmout agreement with Jacobs Energy, L.L.C. (“Jacobs Energy”) of Glasgow,
Kentucky related to development of the Company’s 1,405 leased acres in Hancock
County, Tennessee and an additional area of approximately 20,000 surrounding
acres constituting an area of mutual interest (“AMI”) for the purpose of
exploring the rim of the Swan Creek anticline for Devonian shale gas
production. The agreement was in the form of a “drill to earn”
relationship whereby Jacobs Energy was to establish commercial production at its
sole cost from the first two test wells in order to earn a 50% interest in the
two test wells and right to participate on a fifty-fifty basis in all remaining
wells that may be drilled in the AMI. The Company had no obligation
for any of the costs of the two test wells. The Company would bear
50% of the costs of any new wells drilled in the future within the
AMI. In the event commercial production was not established, Jacobs
Energy would not earn any interest in the test wells nor in the AMI and the
farmout agreement would terminate.
By the end of 2008, Jacobs Energy had
re-completed the Ted Hall No. 1 well, which constituted the completion of the
first of the two test wells under the farmout agreement. On July 8,
2009, the Company terminated the farmout agreement with Jacobs Energy under its
terms. The Company determined that the first of the two test wells contemplated
by the agreement was not properly completed and evaluated for nitrogen content.
It was never determined how much of the nitrogen was occurring naturally, and
how much was a result of the completion management. Second, the Company
determined that Jacobs Energy had failed to perform in a commercially timely
manner by not having yet drilled the second test well. Jacobs
Energy had stated to the Company in early July 2009 that for the foreseeable
future it would not be economically feasible for Jacobs Energy to drill the
second test well based on Jacobs’s assessment of the current state of the
financial markets. Based on that statement, together with the removal
of Jacobs’ equipment from the first well, the Company determined that Jacobs had
abandoned its obligations under the agreement, constituting a separate basis for
the Company’s termination of the agreement. Because the agreement was
terminated, no assignments of any interest in any properties were made, and no
such assignments are due to be conveyed to Jacobs Energy,
The
Company continues to seek development of these properties with other industry
partners as it remains possible that when more than one well is drilled, it may
be economically feasible to treat (if necessary) the produced gas as required,
and to construct gathering facilities necessary to connect to the Company’s
pipeline to bring the gas to market. To date no industry partners
have been found by the Company to further explore these properties and no
assurances can be made that such a partner can be found or that an agreement may
be reached with such partner on terms acceptable to the Company.
9
3. Methane
Project
On
October 24, 2006, the Company signed a twenty-year Landfill Gas Sale and
Purchase Agreement (the “Agreement”) with BFI Waste Systems of Tennessee, LLC
(“BFI”), an affiliate of Allied Waste Industries (“Allied”). In 2008, Allied
merged into Republic Services, Inc. (“Republic”). The Company assigned its
interest in the Agreement to MMC and provides that MMC will purchase the entire
naturally produced gas stream being collected at the Carter Valley municipal
solid waste landfill owned and operated by Republic in Church Hill, Tennessee
serving the metropolitan area of Kingsport, Tennessee. Republic’s
facility is located about two miles from the Company’s pipeline. The
Company installed a proprietary combination of advanced gas treatment technology
to extract the methane component of the purchased gas stream. Methane is
the principal component of natural gas and makes up about half of the purchased
raw gas stream by volume. The Company has constructed a pipeline to
deliver the extracted methane gas to the Company’s existing pipeline (the
“Methane Project”).
The total
cost for the Methane Project, including pipeline construction, was approximately
$4.5 million. The costs of the Methane Project were funded primarily by (a) the
money received by the Company from Hoactzin to purchase its interest in the Ten
Well Program which exceeded the Company’s actual costs of drilling the wells in
that Program by more than $1 million; (b) cash flow from the Company’s
operations; and (c) $0.8 million of the funds the Company borrowed under its
credit facility with Sovereign Bank of Dallas, Texas (“Sovereign Bank”). Methane
gas produced by the project facilities was initially mixed in the Company’s
pipeline and delivered and sold to Eastman under the terms of the Company’s
natural gas purchase and sale agreement with Eastman. At current gas production
rates in the landfill itself and expected extraction efficiencies, the Company
estimates it will be able to produce and deliver about 400 Mcfd of methane sales
gas. The gas supply from this landfill is projected to grow over the
years as the underlying operating landfill continues to expand and generate
additional naturally produced gas, and for several years following the closing
of the landfill, estimated by Republic to occur between the years 2022 and
2029. Gas production will continue in commercial quantities up to 15
years after closure of the landfill.
As part
of the Methane Project agreement, the Company agreed to install a new force-main
water drainage line for Republic, the landfill owner, in the same two-mile
pipeline trench as the gas pipeline needed for the Project, reducing overall
costs and avoiding environmental effects to private landowners resulting from
multiple installations of pipeline. Republic paid the additional
material costs for including the water line of approximately $0.7
million. As a certificated utility, the Company’s pipeline
subsidiary, TPC, required no additional permits for the gas pipeline
construction.
Initial
test volumes of methane were produced in late December 2008. During
the first two months of 2009, Eastman was reviewing its current air quality
permits with regard to MMC’s methane production and deliveries did not occur
during that review.
MMC
declared startup of commercial operations on April 1,
2009. During the month of April, the facility produced and sold
14 MMcf of methane gas to Eastman and was online about 91% of the calendar
month. System maintenance and landfill supply adjustments accounted for the
remainder of the time. On May 1, 2009, Eastman advised MMC that it
was suspending deliveries of the methane gas stream pending approval by the
federal Environmental Protection Agency (“EPA”) of Eastman’s petition for
inclusion of treated methane gas as natural gas within the meaning of the EPA’s
continuous emission
10
monitoring
rules applicable to Eastman’s large boilers during the annual “smog season”
beginning May 1 of each year. Although Eastman had begun seeking this
approval in February, 2009, with the assistance of the Air Quality Department of
the Tennessee Department of Environment and Conservation, the EPA had not acted
by May 1. Eastman furnished to the EPA information provided by MMC
that establishes that the methane gas stream is better fuel under the rule
standards than even “natural” gas, which is technically defined in the smog
season rules to include gas being “found in geologic formations beneath the
earth’s surface”. Methane sales to Eastman were intended to resume
upon EPA’s formal approval of Eastman’s petition or expansion of the regulatory
definition, or both. However, as of December 31, 2009 neither of
these actions has been taken by EPA, despite the existence of EPA’s own
established agency initiative, the Landfill Methane Outreach Program, which is
intended to encourage beneficial use of the methane component of raw landfill
gas. Because approval was not received, MMC was forced to seek
alternative markets for the methane gas stream.
The
Company concluded an agreement for sale of the methane gas to Hawkins County Gas
Utility, a local utility commencing August 1, 2009 on a month to month basis
until either sales to Eastman may resume or other customers were located by the
Company.
Effective
September 1, 2009 the Company began sales of its Swan Creek gas production to
Hawkins County Gas Utility District, because the physical mixing of Swan Creek
natural gas with MMC’s methane gas caused Eastman to suspend deliveries of both
categories of gas as mixed.
On August
27, 2009, the Company entered into a five-year fixed price gas sales contract
with Atmos Energy Marketing, LLC, (“AEM”) in Houston, Texas, a nonregulated unit
of Atmos Energy Corporation (NYSE: ATO) for the sale of the methane component of
landfill gas produced by MMC at the Carter Valley Landfill. The
agreement provides for the sale of up to 600 MMBtu per day. The
contract is effective beginning with September 2009 gas production and ends July
31, 2014. The agreed contract price of over $6 per MMBtu was a
premium to the then current five-year strip price for natural gas on the NYMEX
futures market.
MMC’s
plant is capable of producing a daily average of about 400 Mcfd of methane from
the Carter Valley landfill at current raw gas volumes. However, daily
production during September and October 2009 at MMC’s facility was intermittent
due to a combination of temporary factors. Average daily production
for September and October 2009 was 248 Mcfd on the twenty days the plant was in
production. In November 2009, MMC’s average daily gas production on
producing days was 288 Mcfd of sales methane and in December 2009, this amount
was 293 Mcfd of sales methane.
On September 17, 2007, Hoactzin,
simultaneously with subscribing to participate in the Ten Well Program (the
“Program”), pursuant to a separate agreement with the Company was conveyed a 75%
net profits interest in the Methane Project. The revenues from the Methane
Project received by Hoactzin are to be applied towards the determination of the
Payout Point (as defined above) for the Ten Well Program. When the
Payout Point is reached from either the revenues from the wells drilled in the
Program or the Methane Project or a combination thereof, Hoactzin’s net profits
interest in the Methane Project will decrease to a 7.5% net profits
interest. The Company believes that the application of revenues
from the Methane Project to reach the Payout Point could accelerate reaching the
Payout Point. As stated above, the Purchase Price paid by Hoactzin
for its interest in the Program exceeded the Company’s anticipated
11
and
actual costs of drilling the ten wells in the Program. Those excess funds
provided by Hoactzin were used to pay for approximately $1 million of equipment
required for the Methane Project, or about 22% of the Project’s capital
costs. The availability of the funds provided by Hoactzin eliminated
the need for the Company to borrow those funds, to have to pay interest to any
lending institution making such loans or to dedicate Company revenues or
revenues from the Methane Project to pay such debt
service. Accordingly, the grant of a 7.5% interest in the Methane
Project to Hoactzin was negotiated by the Company as a favorable element to the
Company of the overall transaction.
4. Management
Agreement with Hoactzin
The Company entered into a Management
Agreement with Hoactzin on December 17, 2007. On that same date, the
Company entered into an agreement with Charles Patrick McInturff employing him
as a Vice-President of the Company. Pursuant to the Management
Agreement with Hoactzin, Mr. McInturff’s duties while he is employed as
Vice-President of the Company will include the management on behalf of Hoactzin
of its working interest in certain oil and gas properties owned by Hoactzin and
located in the onshore Texas Gulf Coast, and offshore Texas and offshore
Louisiana. As consideration for the Company entering into the
Management Agreement, Hoactzin agreed that it will reimburse the Company for
one-half of Mr. McInturff’s salary, as well as certain other benefits he
receives during his employment by the Company. In further
consideration for the Company’s agreement to enter into the Management
Agreement, Hoactzin granted to the Company an option to participate in up to a
15% working interest for a corresponding price of up to 15% of the actual
project costs, in any new drilling or work-over activities undertaken on
Hoactzin’s managed properties during the term of the Management
Agreement. During 2009, the Company participated in an unsuccessful
workover on West Delta 62 and spent $0.2 million or 15% of the total workover
cost. The Company was able to recoup approximately one third of the
cost prior to the well ceasing production. The Company did not participate in
any additional projects and will not consider participation in any future
projects unless and until gas prices increase. The term of the
Management Agreement is the earlier of the period ending with the date Hoactzin
conveys its interest in its managed properties or 5 years from the date of the
agreement.
5. Other
Areas of Development
The Company is continuing to review and
analyze potential acquisitions of additional existing oil and gas production in
areas of Kansas, Oklahoma, and Texas. Whether the Company will
proceed with any such acquisition it deems appropriate will be dependent on a
number of factors, including available financing, oil prices,
etc. Current economic conditions, including any sharp decline in oil
prices, will certainly have an adverse impact on the Company’s ability to
acquire additional properties. Accordingly, there is no assurance that a
suitable property will become available or even if such property becomes
available that terms will be established leading to a completion of such a
purchase.
The Company has evaluated other
geological structures in the East Tennessee area that are similar to the Swan
Creek Field. While these areas are of interest, and may be further
evaluated at some future time, based on its review to date the Company does not
currently intend to actively explore these areas with its own
funds. The Company may consider entering into partnerships where
further exploration and drilling costs can be largely borne by third
parties. There can be no assurances that any third party
would
12
participate
in a drilling program in these structures, that any of these prospects will be
drilled, and if they were drilled that they would result in commercial
production.
The Company also intends to establish
and explore all business opportunities for connection of the pipeline system
owned by the Company’s subsidiary TPC to other sources of natural gas or gas
produced from non-conventional sources so that revenues from third parties for
transportation of gas across the pipeline system may be
generated. Although no assurances can be made, such connections may
also enable the Company to purchase natural gas from other sources and to then
market natural gas to new customers in the Kingsport, Tennessee area at retail
rates under a franchise agreement already granted to the Company by the City of
Kingsport, subject to approval by the Tennessee Regulatory
Authority.
The Company also intends to continue to
explore other opportunities such as its Methane Project in Church Hill,
Tennessee to obtain natural gas or substitutes for natural gas from
non-conventional sources if such gas can be economically treated and tendered in
commercial volumes for transportation not only through the Company’s existing
pipeline system but by other delivery mechanisms and through other interstate or
intrastate pipelines or local distribution companies for the purposes of
supplementing the Company’s revenues from the sale of the methane gas produced
by these projects.
Governmental
Regulations
The Company is subject to numerous
state and federal regulations, environmental and otherwise, that may have a
substantial negative effect on its ability to operate at a
profit. For a discussion of the risks involved as a result of such
regulations, see, “Effect of Existing or Probable Governmental Regulations on
Business and Costs and Effects of Compliance with Environmental Laws”
hereinafter in this section.
Principal
Products or Services and Markets
The principal markets for the Company’s
crude oil are local refining companies. The principal markets for the
Company’s natural gas and methane production are local utilities, private
industry end-users, and gas marketing companies.
Gas production from the Swan Creek
Field can presently be delivered through the Company’s completed pipeline to the
Powell Valley Utility District in Hancock County, Hawkins County Gas Utility,
Eastman and BAE in Sullivan County, as well as other industrial customers in the
Kingsport area. The Company has acquired all necessary regulatory
approvals and necessary property rights for the pipeline system. The
Company’s pipeline can provide transportation service not only for gas produced
from the Company’s wells, but also for small independent producers in the local
area as well or other pipelines that may be connected to the Company’s pipeline
in the future.
At present, crude oil produced by the
Company in Kansas is sold at or near the wells to Coffeyville Resources Refining
and Marketing; LLC (“Coffeyville Refining”) in Kansas City, Kansas. Coffeyville
Refining is solely responsible for transportation to its refinery of the oil it
purchases. The Company may sell some or all of its production to one
or more additional refineries in order to maximize revenues as purchases prices
offered by the refineries fluctuate from time to time. Crude oil
produced by the Company in Tennessee is sold to the Ashland Refinery in Kentucky
and is transported to the refinery by contracted truck delivery at the Company’s
expense.
13
Drilling
Equipment
The Company does not currently own a
drilling rig or any related drilling equipment. The Company obtains
drilling services as required from time to time from various companies as
available in the Swan Creek Field area and various drilling contractors in
Kansas.
Distribution
Methods of Products or Services
Crude oil is normally delivered to
refineries in Tennessee and Kansas by tank truck and natural gas is distributed
and transported by pipeline.
Competitive
Business Conditions, Competitive Position in the Industry and Methods of
Competition
The Company’s contemplated oil and gas
exploration activities in the States of Tennessee and Kansas will be undertaken
in a highly competitive and speculative business atmosphere. In
seeking any other suitable oil and gas properties for acquisition, the Company
will be competing with a number of other companies, including large oil and gas
companies and other independent operators with greater financial
resources. Management does not believe that the Company’s competitive
position in the oil and gas industry will be significant as the Company
currently exists.
The Company has numerous competitors in
the State of Tennessee that are in the business of exploring for and producing
oil and natural gas in Kentucky and East Tennessee areas. Some of
these companies are larger than the Company and have greater financial
resources. These companies are in competition with the Company for
lease positions in the known producing areas in which the Company currently
operates, as well as other potential areas of interest.
There are numerous producers in the
area of the Kansas Properties. Some are larger with greater financial
resources.
Although management does not foresee
any difficulties in procuring contracted drilling rigs, several factors,
including increased competition in the area, may limit the availability of
drilling rigs, rig operators and related personnel and/or equipment in the
future. Such limitations would have a natural adverse impact on the
profitability of the Company’s operations.
The Company anticipates no difficulty
in procuring well drilling permits in any state. They are usually
issued within one week of application. The Company generally does not
apply for a permit until it is actually ready to commence drilling
operations.
The prices of the Company’s products
are controlled by the world oil market and the United States natural gas
market. Thus, competitive pricing behaviors are considered unlikely;
however, competition in the oil and gas exploration industry exists in the form
of competition to acquire the most promising acreage blocks and obtaining the
most favorable process for transporting the product.
14
Sources
and Availability of Raw Materials
Excluding the development of oil and
gas reserves and the production of oil and gas, the Company’s operations are not
dependent on the acquisition of any raw materials.
Dependence
on One or a Few Major Customers
The Company is presently dependent upon
a small number of customers for the sale of gas from the Swan Creek Field and
the Methane Project principally gas marketing companies, utility districts, and
industrial customers in the Kingsport area with which the Company may enter into
gas sales contracts.
At present, crude oil from the Kansas
Properties is being purchased at the well and trucked by Coffeyville Refining,
which is responsible for transportation of the crude oil
purchased. The Company may sell some or all of its production to one
or more additional refineries in order to maximize revenues as purchase prices
offered by the refineries fluctuate from time to time.
Patents,
Trademarks, Licenses, Franchises, Concessions, Royalty Agreements or Labor
Contracts, Including Duration
None.
Need
For Governmental Approval of Principal Products or Services
None of the principal products offered
by the Company require governmental approval, although permits are required for
drilling oil or gas wells. In addition the transportation service
offered by TPC is subject to regulation by the Tennessee Regulatory Authority to
the extent of certain construction, safety, tariff rates and charges, and
nondiscrimination requirements under state law. These requirements
are typical of those imposed on regulated common carriers or utilities in the
State of Tennessee or in other states. TPC presently has all required
tariffs and approvals necessary to transport natural gas to all customers of the
Company.
The City of Kingsport, Tennessee has
enacted an ordinance granting to TPC a franchise for twenty years to construct,
maintain and operate a gas system to import, transport, and sell natural gas to
the City of Kingsport and its inhabitants, institutions and businesses for
domestic, commercial, industrial and institutional uses. This
ordinance and the franchise agreement it authorizes also require approval of the
Tennessee Regulatory Authority under state law. The Company will not
initiate the required approval process for the ordinance and franchise agreement
until such time that it can supply gas to the City of
Kingsport. Although the Company anticipates that regulatory approval
would be granted, there can be no assurances that it would be granted, or that
such approval would be granted in a timely manner, or that such approval would
not be limited in some manner by the Tennessee Regulatory
Authority.
Effect
of Existing or Probable Governmental Regulations on Business
Exploration and production activities
relating to oil and gas leases are subject to numerous environmental laws, rules
and regulations. The Federal Clean Water Act requires the Company to
construct a fresh water containment barrier between the surface of each drilling
site and the underlying water table. This involves the insertion of
steel casing into each well, with cement on the outside of the
15
casing. The
Company has fully complied with this environmental regulation, the cost of which
is approximately $10,000 per well.
The State of Tennessee also requires
the posting of a bond to ensure that the Company’s wells are properly plugged
when abandoned. A separate $2,000 bond is required for each well
drilled. The Company currently has the requisite amount of bonds in
effect.
As part of the Company’s purchase of
the Kansas Properties we acquired a statewide permit to drill in
Kansas. Applications under such permit are applied for and issued
within one to two weeks prior to drilling. At the present time, the
State of Kansas does not require the posting of a bond either for permitting or
to insure that the Company’s wells are properly plugged when
abandoned. All of the wells in the Kansas Properties have all permits
required and the Company believes that it is in compliance with the laws of the
State of Kansas.
The Company’s exploration, production
and marketing operations are regulated extensively at the federal, state and
local levels. The Company has made and will continue to make
expenditures in its efforts to comply with the requirements of environmental and
other regulations. Further, the oil and gas regulatory environment
could change in ways that might substantially increase these
costs. Hydrocarbon-producing states regulate conservation practices
and the protection of correlative rights. These regulations affect
the Company’s operations and limit the quantity of hydrocarbons it may produce
and sell. In addition, at the federal level, the Federal Energy
Regulatory Commission regulates interstate transportation of natural gas under
the Natural Gas Act. Other regulated matters include marketing,
pricing, transportation and valuation of royalty payments.
The Company’s operations are also
subject to numerous and frequently changing laws and regulations governing the
discharge of materials into the environment or otherwise relating to
environmental protection. The Company owns or leases, and has in the
past owned or leased, properties that have been used for the exploration and
production of oil and gas and these properties and the wastes disposed on these
properties may be subject to the Comprehensive Environmental Response,
Compensation and Liability Act, the Oil Pollution Act of 1990, the Resource
Conservation and Recovery Act, the Federal Water Pollution Control Act and
analogous state laws. Under such laws, the Company could be required
to remove or remediate preciously released wastes or property
contamination.
16
Laws and
regulations protecting the environment have generally become more stringent and,
may in some cases, impose “strict liability” for environmental
damage. Strict liability means that the Company may be held liable
for damage without regard to whether it was negligent or otherwise at
fault. Environmental laws and regulations may expose the Company to
liability for the conduct of or conditions caused by others or for acts that
were in compliance with all applicable laws at the time they were
performed. Failure to comply with these laws and regulations may
result in the imposition of administrative, civil and criminal
penalties.
While management believes that the
Company’s operations are in substantial compliance with existing requirements of
governmental bodies, the Company’s ability to conduct continued operations is
subject to satisfying applicable regulatory and permitting
controls. The Company’s current permits and authorizations and
ability to get future permits and authorizations may be susceptible, on a going
forward basis, to increased scrutiny, greater complexity resulting in increased
costs or delays in receiving appropriate authorizations.
The Company’s Board of Directors has
adopted resolutions to form an Environmental Response Policy and Emergency
Action Response Policy Program. A plan was adopted which provides for
the erection of signs at each well and at strategic locations along the pipeline
containing telephone numbers of the Company’s office. A list is
maintained at the Company’s office and at the home of key personnel listing
phone numbers for fire, police, emergency services and Company employees who
will be needed to deal with emergencies.
The foregoing is only a brief summary
of some of the existing environmental laws, rules and regulations to which the
Company’s business operations are subject, and there are many others, the
effects of which could have an adverse impact on the Company. Future
legislation in this area will no doubt be enacted and revisions will be made in
current laws. No assurance can be given as to that affect these
present and future laws, rules and regulations will have on the Company’s
current and future operations.
Research
and Development
None.
Number
of Total Employees and Number of Full-Time Employees
The Company presently has 29 full time
employees and no part-time employees.
17
Executive
Officers of the Registrant
Identification of Executive
Officers
The
following table sets forth the names of all current executive officers of the
Company. These persons will serve until their successors are elected
or appointed and qualified, or their prior resignations or
terminations.
|
Name
|
Positions
Held
|
Date
of Initial
Election
of Designation
|
|
Jeffrey
R. Bailey
|
Chief
Executive Officer
1
|
6/17/2002
|
|
Charles
Patrick McInturff
|
Vice-President
|
12/18/2007
|
|
Cary
V. Sorensen
|
Vice-President;
General Counsel; Secretary
|
7/09/1999
|
|
Michael
J. Rugen
|
Chief
Financial Officer
|
9/28/2009
|
Business
Experience
2
Charles Patrick McInturff is 57 years
old. Mr. McInturff received a Bachelor of Science Degree in Civil Engineering
from Texas A&M University in 1975. He is a Registered
Professional Engineering from Texas and a member of the Society of Petroleum
Engineers. Before joining the Company he was Vice President of
Operations of Capco Offshore, Inc. and related companies in Houston from
October 2006 until December 2007 responsible for managing and
supervising offshore operations and workovers and identification and evaluation
of drilling and workover candidates. From 1991 to 2006, he was
employed by Ryder Scott Company in Houston performing reservoir studies
including determination of oil, gas, condensate and plant product reserves,
enhanced recovery and oil and gas property appraisal. For most
of the period 1978 to 1991, he worked in various petroleum engineering positions
at Union Texas Petroleum Corp. in Midland and Houston, Texas, and Karachi,
Pakistan and was responsible for surveillance and engineering on primary and
secondary recovery projects as well as design and field supervision of
workovers, pressure-transient tests and completions both onshore and
offshore.
2
The
background and business experience of Jeffrey R. Bailey is incorporated by
reference from the section entitled “Proposal No. 1. Election of Directors” in
the Company’s Proxy Statement for the Company’s 2010 Annual Meeting of
Stockholders.
18
During
that time period he also worked for Global Natural Resources from 1983 to 1986
as senior operations engineer responsible for all engineering
activities. From 1981 to 1983 he was employed by Belco Petroleum
performing reservoir engineering duties including field studies, economic
evaluation, reserves estimation, and initiating major field studies on
waterflood projects in southwestern Wyoming and west Texas. Mr.
McInturff was employed by Exxon Co. USA from 1975 to 1978 primarily with the
reservoir engineering group in Midland, Texas performing drilling engineering
duties including cost estimation, AFE preparation, drilling programs and field
supervision. He was responsible for the surveillance of fifteen
Permian Basin oil and gas fields in west Texas using both primary and secondary
recovery techniques. On December 18, 2007, he was appointed to serve
as Vice-President of the Company.
Cary V. Sorensen is 61 years old. He is
a 1976 graduate of the University of Texas School of Law and has undergraduate
and graduate degrees from North Texas State University and Catholic University
in Washington, D.C. Prior to joining the Company in July 1999, he had been
continuously engaged in the practice of law in Houston, Texas relating to the
energy industry since 1977, both in private law firms and a corporate law
department, serving for seven years as senior counsel with the oil and gas
litigation department of a Fortune 100 energy corporation in Houston before
entering private practice in June, 1996. He has represented virtually
all of the major oil companies headquartered in Houston as well as local
distribution companies and electric utilities in a variety of litigated and
administrative cases before state and federal courts and agencies in nine
states. These matters involved gas contracts, gas marketing,
exploration and production disputes involving royalties or operating interests,
land titles, oil pipelines and gas pipeline tariff matters at the state and
federal levels, and general operation and regulation of interstate and
intrastate gas pipelines. He has served as General Counsel of the
Company since July 9, 1999.
Michael J. Rugen is 49 years old and
was named Tengasco Chief Financial Officer in September 2009. He is a
certified public accountant (Texas) with over 27 years of experience in
exploration and production and oilfield service. Prior to joining
Tengasco, Mr. Rugen spent 2 years as Vice President of Accounting and Finance
for Nighthawk Oilfield Services. From 2001 to June 2007, he was a
Manager/Sr. Manager with UHY Advisors, primarily responsible for managing
internal audit and Sarbanes-Oxley 404 engagements for various oil and gas
clients. In 1999 and 2000, Mr. Rugen provided finance and accounting consulting
services with Jefferson Wells International. From 1982 to 1998, Mr.
Rugen held various accounting and management positions at BHP Petroleum, with
accounting responsibilities for onshore and offshore US operations as well as
operations in Trinidad and Boliva. Mr. Rugen earned a Bachelor of
Science in Accounting in 1982 from Indiana University.
19
Code
of Ethics
The Company’s Board of Directors has
adopted a Code of Ethics that applies to the Company’s financial officers and
executives officers, including its Chief Executive Officer and Chief Financial
Officer. The Company’s Board of Directors has also adopted a Code of
Conduct and Ethics for Directors, Officers and Employees. A copy of
these codes can be found at the Company’s internet website at
www.tengasco.com. The Company intends to disclose any amendments to
its Codes of Ethics, and any waiver from a provision of the Code of Ethics
granted to the Company’s President, Chief Financial Officer or persons
performing similar functions, on the Company’s internet website within five
business days following such amendment or waiver. A copy of the Code
of Ethics can be obtained free of charge by writing to Cary V. Sorensen,
Secretary, Tengasco, Inc., 11121 Kingston Pike, Suite E, Knoxville, TN
37934.
Available
Information
The Company is a reporting company, as
that term is defined under the Securities Acts, and therefore files reports,
including Quarterly Reports on Form 10-Q and Annual Reports on Form 10-K such as
this Report, proxy information statements and other materials with the
Securities and Exchange Commission (“SEC”). You may read and copy any
materials the Company files with the SEC at the SEC’s Public Reference Room at
450 Fifty Street, N.W., Washington D.C. 20549 upon payment of the prescribed
fees. You may obtain information on the operation of the Public
Reference Room by calling the SEC at 1-800 SEC-0330.
In addition, the Company is an
electronic filer and files its Reports and information with the SEC through the
SEC’s Electronic Data Gathering, Analysis and Retrieval system
(“EDGAR”). The SEC maintains a website that contains reports, proxy
and information statements and other information regarding issuers that file
electronically through EDGAR with the SEC, including all of the Company’s
filings with the SEC. The address of that site is
http://www.sec.gov.
The Company’s website is located at
http://www.tengasco.com. On the home page of the website, you may
access, free of charge, the Company’s Annual Report on Form 10-K. Under the
Investor Information /SEC filings tab you will find the Quarterly Reports on
Form 10-Q, Current Reports on Form 8-K, Section 16 filings (Form 3, 4 and 5) and
any amendments to those reports as reasonably practicable after the Company
electronically files such reports with the SEC. The information
contained on the Company’s website is not part of the Report or any other report
filed with the SEC.
20
In addition to the other information
included in this Form 10-K, the following risk factors should be considered in
evaluating the Company’s business and future prospects. The risk
factors described below are not exhaustive and you are encouraged to perform
your own investigation with respect to the Company and its
business. You should also read the other information included in this
Form 10-K, including the financial statements and related notes.
The
Company’s indebtedness, the current global recession, and disruption in the
domestic and global financial markets could have an adverse effect on the
Company’s operating results and financial condition.
As of December 31, 2009, the
outstanding principal amount of the Company’s indebtedness to Sovereign Bank was
approximately $9.9 million. The level of indebtedness, coupled with
the widely reported domestic and global recession, the associated low levels of
energy prices, and the unprecedented levels of disruption and continuing
relative illiquidity in the credit markets may, if continued for an extended
period, have several important and adverse consequences on the Company’s
business and operations. For example, any one or more of these
factors could (i) make it difficult for the Company to service or refinance its
existing indebtedness; (ii) increase the Company’s vulnerability to additional
adverse changes in economic and industry conditions; (iii) require the Company
to dedicate a substantial portion or all of its cash flow from operations and
proceeds of any debt or equity issuances or asset sales to pay or provide for
its indebtedness; (iv) limit the Company’s ability to respond to changes in our
businesses and the markets in which we operate; (v) place the Company at a
disadvantage to our competitors that are not as highly leveraged; or (vi) limit
the Company’s ability to borrow money or raise equity to fund our working
capital, capital expenditures, acquisitions, debt service requirements,
investments, general corporate activity or other financing needs. The
Company continues to closely monitor the recent disruption in the global
financial and credit markets, as well as the recent significant decline in the
market prices for oil and natural gas. As these events unfold, the
Company will continue to evaluate and respond to any impact on Company
operations. The Company has and will continue to adjust and reduce
its drilling plans and capital expenditures as necessary. However,
externally financing in the capital markets is currently not readily available,
and without adequate capital resources, the Company’s drilling and other
activities may be limited and the Company’s business, financial condition and
results of operations may suffer. Additionally, in light of the
current credit markets and the pricing for oil and natural gas, the Company’s
ability to enter into future beneficial relationships with third parties for
exploration and production activities may be limited, and as a result, may have
an adverse effect on current operational strategy and related business
initiatives.
As of
September 30, 2009, the Company was out of compliance on the Leverage Ratio and
Interest Coverage Ratio covenants under the Sovereign credit
facility. The Company was in compliance with the remaining financial
covenants under the credit facility. The noncompliance occurred
primarily as a result of the low commodity prices in the last quarter of 2008
and first and second quarters of 2009 that are included in the covenant
compliance calculations. The Company has received a waiver from
Sovereign Bank for noncompliance of these covenants for the quarter ended
September 30, 2009. There can be no assurances that Sovereign Bank
will waive noncompliance of covenants should future instances
occur.
21
Agreements
Governing the Company’s Indebtedness may Limit the Company’s Ability to Execute
Capital Spending or to Respond to Other Initiatives or Opportunities as they May
Arise.
Because the availability of borrowings
by the Company under the terms of the Company’s amended and restated credit
facility with Sovereign Bank is subject to an upper limit of the borrowing base
as determined by the lender’s calculated estimated future cash flows from the
Company’s oil and natural gas reserves, the Company expects any sharp decline in
the pricing for these commodities, if continued for any extended period, would
very likely result in a reduction in the Company’s borrowing base. A
reduction in the Company’s borrowing base could be significant and as a result,
would not only reduce the capital available to the Company but may also require
repayment of principal to the lender under the terms of the facility.
Additionally, the terms of the Company’s amended and restated credit facility
with Sovereign bank restrict the Company’s ability to incur additional
debt. The credit facility contains covenants and other restrictions
customary for oil and gas borrowing base credit facilities, including
limitations on debt, liens, and dividends, voluntary redemptions of debt,
investments, and asset sales. In addition, the credit facility
requires that the Company maintain compliance with certain financial tests and
financial covenants. If future debt financing is not available to the
Company when required as a result of limited access to the credit markets or
otherwise, or is not available on acceptable terms, the Company may be unable to
invest needed capital for drilling and exploration activities, take advantage of
business opportunities, respond to competitive pressures or refinance maturing
debt. In addition, the Company may be forced to sell some of the
Company’s assets on an untimely basis or under unfavorable terms. Any
of these results could have a material adverse effect on the Company’s operating
results and financial conditions.
The
Company’s Borrowing Base under its Credit Facility may be Reduced by Sovereign
Bank.
The borrowing base under the Company’s
revolving credit facility with Sovereign Bank will be determined from time to
time by the lender, as specified in the credit facility, consistent with its
customary natural gas and crude oil lending practices. Reductions in
estimates of the Company’s natural gas and crude oil reserves under the
parameters established by the lender could result in a reduction in the
Company’s borrowing base, which would reduce the amount of financial resources
available under the Company’s revolving credit facility to meet its capital
requirements. Such a reduction could be the result of lower commodity
prices or production, inability to drill or unfavorable drilling results,
changes in natural gas and crude oil reserve engineering, the lender’s inability
to agree to an adequate borrowing base or adverse changes in the lender’s
practices regarding estimation of reserves. If cash flow from operations or the
Company’s borrowing base decrease for any reason, the Company’s ability to
undertake exploration and development activities could be adversely
affected. As a result, the Company’s ability to replace production
may be limited. In addition, if the borrowing base under the
Company’s Sovereign Bank revolving credit facility is reduced, the Company could
be required to pay down its borrowings under the revolving credit facility so
that outstanding borrowings do not exceed the reduced borrowing
base. This could further reduce the cash available to the Company for
capital spending and, if the Company did not have sufficient capital to reduce
its borrowing level, could cause the Company to default under its revolving
credit facility with Sovereign Bank.
22
The
Company’s Credit Facility with Sovereign Bank is Subject to Variable Rates of
Interest, Which Could Negatively Impact the Company.
Borrowings under the Company’s credit
facility with Sovereign Bank are at variable rates of interest and expose the
Company to interest rate risk. If interest rates increase, the
Company’s debt service obligations on the variable rate indebtedness would
increase even though the amount borrowed remained the same, and the Company’s
income and cash flows would decrease. The Company’s credit facility
agreement contains certain financial covenants based on the Company’s
performance. If the Company’s financial performance results in any of
these covenants being violated, Sovereign Bank may choose to require repayment
of the outstanding borrowings sooner than currently required by the
agreement.
Declines
in Oil or Gas Prices Have and Will Materially Adversely Affect the Company’s
Revenues.
The
Company’s financial condition and results of operations depend in large part
upon the prices obtainable for the Company’s oil and natural gas production and
the costs of finding, acquiring, developing and producing
reserves. As seen in 2008 and 2009 prices for oil and natural gas are
subject to extreme fluctuations in response to changes in supply, market
uncertainty and a variety of additional factors that are beyond the Company’s
control. These factors include worldwide political instability
(especially in the Middle East and other oil producing regions), the foreign
supply of oil and gas, the price of foreign imports, the level of drilling
activity, the level of consumer product demand, government regulations and
taxes, the price and availability of alternative fuels speculating activities in
the commodities markets and the overall economic environment. For example,
during 2008, the price for oil was extremely volatile. In July 2008,
the price of oil which had reached a record high of $147 per barrel had declined
to approximately $35 per barrel by December 2008 and increased to $74 per barrel
by December 2009. The Company’s operations are substantially
adversely impacted as oil prices decline. Lower prices dramatically
affect the Company’s revenues from its drilling operations. Further,
drilling of new wells, development of the Company’s leases and acquisitions of
new properties are also adversely affected and limited. As a
result, the Company’s potential revenues from operations as well as the
Company’s proved reserves may substantially decrease from levels achieved during
the period when oil prices were much higher. There can be no
assurances as to the future prices of oil or gas. A substantial or
extended decline in oil or gas prices would have a material adverse effect on
the Company’s financial position, results of operations, quantities of oil and
gas that may be economically produced, and access to capital. Oil and
natural gas prices have historically been and are likely to continue to be
volatile. This volatility makes it difficult to estimate with
precision the value of producing properties in acquisitions and to budget and
project the return on exploration and development projects involving the
Company’s oil and gas properties. In addition, unusually volatile
prices often disrupt the market for oil and gas properties, as buyers and
sellers have more difficulty agreeing on the purchase price of
properties.
Risk
in Rates of Oil and Gas Production, Development Expenditures, and Cash Flows May
Have a Substantial Impact on the Company’s Finances.
Projecting the effects of commodity
prices on production, and timing of development expenditures include many
factors beyond the Company’s control. The future estimates of net
cash flows from the Company’s proved and other reserves and their present value
are based upon various assumptions about future production levels, prices, and
costs that may prove to be incorrect over time.
23
Any
significant variance from assumptions could result in the actual future net cash
flows being materially different from the estimates, which would have a
significant impact on the Company’s financial position.
The
Company has a History of Significant Losses.
During the early stages of the
development of its oil and gas business the Company had a history of significant
losses from operations, in particular its development of the Swan Creek Field,
and has an accumulated deficit of $28.5 million as of December 31,
2009. Although management has substantially reduced its cash
operating expenses, these losses have had a material adverse impact on the
operations of the Company’s business. The Company was profitable in
2006 and 2007. In 2008, the Company had an operating profit before
ceiling test write down of $4.8 million, but due to non-cash ceiling write-down
limitation of $11.6 million ($7.7 million net of tax effects), the Company
recorded a net income of $0.2 million. The Company recorded a net
loss of $2.0 million in 2009. In the event the Company experiences losses in the
future, those losses may curtail the Company’s development and operating
activities.
The
Company’s Oil and Gas Operations Involve Substantial Cost and are Subject to
Various Economic Risks.
The Company’s oil and gas operations
are subject to the economic risks typically associated with exploration,
development, and production activities, including the necessity of making
significant expenditures to locate or acquire new producing properties or to
drill exploratory and developmental wells. In conducting exploration
and development activities, the presence of unanticipated pressure or
irregularities in formations, miscalculations, and accidents may cause the
Company’s exploration, development, and production activities to be
unsuccessful. This could result in a total loss of the Company’s
investment in such well(s) or property. In addition, the cost of
drilling, completing and operating wells is often uncertain.
The
Company’s Failure to Find or Acquire Additional Reserves Will Result in the
Decline of the Company’s Reserves Materially From Their Current
Levels.
The rate of production from the
Company’s Kansas oil and Tennessee oil and natural gas properties generally
declines as reserves are depleted. Except to the extent that the
Company either acquires additional properties containing proved reserves,
conducts successful exploration and development drilling, or successfully
applies new technologies or identifies additional behind-pipe zones or secondary
recovery reserves, the Company’s properties proved reserves will decline
materially as production from these properties continues. The
Company’s future oil and natural gas production is therefore highly dependent
upon the level of success in acquiring or finding additional reserves or other
alternative sources of production. Any decline in oil prices and any
prolonged period of lower prices will adversely impact the Company’s future
reserves since the Company is less likely to acquire additional producing
properties during such periods. The lower oil prices have a chilling
effect on new drilling and development as such activities become far less likely
to be profitable. Thus, any acquisition of new properties poses a
greater risk to the Company’s financial conditions as such acquisitions may be
commercially unreasonable.
24
In addition, the Company’s drilling for
oil and natural gas may involve unprofitable efforts not only from dry wells but
also from wells that are productive but do not produce sufficient volumes to be
commercially profitable after deducting drilling, operating, and other
costs. In addition, wells that are profitable may not achieve a
targeted rate of return. The Company relies on seismic data and other
technologies in identifying prospects and in conducting exploration
activities. The seismic data and other technologies used do not allow
the Company to know conclusively prior to drilling a well whether oil or natural
gas is present or may be produced economically.
The ultimate costs of drilling,
completing, and operating a well can adversely affect the economics of a
project. Further drilling operations may be curtailed, delayed or
canceled as a result of numerous factors, including unexpected drilling
conditions, title problems, pressure or irregularities in formations, equipment
failures or accidents, adverse weather conditions, environmental and
other governmental requirements and the cost of, or shortages or delays in the
availability of drilling rigs, equipment, and services.
The
Company’s Reserve Estimates May Be Subject to Other Material Downward
Revisions.
The Company’s oil reserve estimates or
gas reserve estimates may be subject to material downward revisions for
additional reasons other than the factors mentioned in the previous risk factor
entitled “The Company’s Failure to Find or Acquire Additional Reserves Will
Result in the Decline of the Company’s Reserves Materially from their Current
Levels.” While the future estimates of net cash flows from the
Company’s proved reserves and their present value are based upon assumptions
about future production levels, prices, and costs that may prove to be incorrect
over time, those same assumptions, whether or not they prove to be correct, may
cause the Company to make drilling or developmental decisions that will result
in some or all of the Company’s proved reserves to be removed from time to time
from the proved reserve categories previously reported by the
Company. This is particularly so if the price of oil declines sharply
as it did during the period from mid-2008 through January 2009. This
may occur because economic expectations or forecasts, together with the
Company’s limited resources, may cause the Company to determine that drilling or
development of certain of its properties may be delayed or may not foreseeably
occur, and as a result of such decisions any category of proved reserves
relating to those yet undrilled or undeveloped properties may be removed from
the Company’s reported proved reserves. Consequently, the Company’s
proved reserves of oil or of gas, or both, may be materially revised downward
from time to time. As an example, the Company’s proved Swan Creek gas
reserves have been revised downward in the past few years as a result of removal
of portions of the Company’s reported gas reserves from the “proved undeveloped
category” (“PUD”) and the “proved developed nonproducing” (“PDNP”) categories
because of the Company’s determination that additional drilling or development
of Swan Creek may not occur in the foreseeable future based on the Company’s
determination that the economic returns from such drilling or development would
not be favorable when compared to the costs and anticipated results of such
activity. Although that particular revision at this time will not
have a significant impact on overall results of operations in view of the
relatively small portion of the Company’s current business and assets founded in
natural gas (as opposed to oil where reserves have been materially revised
upward in the same period), other revisions in gas reserves, or in oil reserves,
in the future may be significant and materially reduce oil or gas
reserves.
25
In
addition, the Company may elect to sell some or all of its oil or gas reserves
in the normal course of the Company’s business. Any such sale would
result in all categories of those proved oil or gas reserves that were sold no
longer being reported by the Company.
There
is Risk That the Company May Be Required to Write Down the Carrying Value of its
Natural Gas and Crude Oil Properties.
The Company uses the full cost method
to account for its natural gas and crude oil operations. Accordingly,
the Company capitalizes the cost to acquire, explore for and develop natural gas
and crude oil properties. Under full cost accounting rules, the net
capitalized cost of natural gas and crude oil properties may not exceed a
“ceiling limit” which is based upon the present value of estimated future net
cash flows from proved reserves, discounted at 10%. If net
capitalized cost of natural gas and crude oil properties exceeds the ceiling
limit, the Company must charge the amount of the excess, net of any tax effects,
to earnings. This charge does not impact cash flow from operating
activities, but does reduce the Company’s stockholders equity and
earnings. The risk that the Company will be required to write-down
the carrying value of natural gas and crude oil properties increases when
natural gas and crude oil prices are low. In addition, write-downs
may occur if the Company experiences substantial downward adjustments to its
estimated proved reserves. An expense recorded in a period may not be
reversed in a subsequent period even though higher natural gas and crude oil
prices may have increased the ceiling applicable to the subsequent
period. In 2008, the Company did incur a ceiling limitation
write-down net of tax effects in the amount of $7.7 million due to the
dramatically lower year-end oil prices in 2008 compared to 2007 and the
resulting significant downward adjustment of the Company’s estimated proved
reserves. The effect of the ceiling writedown resulted in the Company
recording net income of $0.2 million in 2008. The Company did not
incur a writedown in 2009 or in 2007.
Use
of the Company’s Net Operating Loss Carryforwards May Be Limited.
At December 31, 2009, the Company had,
subject to the limitations discussed in this risk factor, substantial amounts of
net operating loss carryforwards for U.S. federal income tax
purposes. These loss carryforwards will eventually expire if not
utilized. In addition, as to a portion of the U.S. net operating loss
carryforwards, the amount of such carryforwards that the Company can use
annually is limited under U.S. tax laws. Uncertainties exist as to
both the calculation of the appropriate deferred tax assets based upon the
existence of these loss carryforwards, as well as the future utilization of the
operating loss carryforwards under the criteria set forth under FASB ASC 740,
Income Taxes. In addition, limitations exist upon use of these carryforwards in
the event of a change in control of the Company occurs. There are
risks that the Company many not be able to utilize some or all of the remaining
carry forwards, or that deferred tax assets that were previously booked based
upon such carryforwards may be written down or reversed based on future economic
factors that may be experienced by the Company. The effect of
such write downs or reversals, if they occur, may be material and substantially
adverse.
26
Shortages of Oil Field Equipment,
Services and Qualified Personnel Could Adversely Affect the Company’s Results of
Operations
.
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. The Company does
not own any drilling rigs and is dependent upon third parties to obtain and
provide such equipment as needed for the Company’s drilling
activities. There have also been shortages of drilling rigs and other
equipment when oil prices have risen and as a result the demand for rigs and
equipment when oil prices have risen and as a result the demand for rigs and
equipment increased along with the number of wells being
drilled. These factors also cause significant increases in costs for
equipment, services and personnel. Higher oil and natural gas prices
generally stimulate increased demand and result in increased prices for drilling
rigs, crews and associated supplies, equipment and services. These
shortages or price increases could adversely affect the Company’s profit margin,
cash flow, and operating results or restrict the Company’s ability to drill
wells and conduct ordinary operations.
The
Company has Significant Costs to
Conform to Government Regulation of the Oil and Gas
Industry.
The Company’s exploration, production,
and marketing operations are regulated extensively at the federal, state and
local levels. The Company is currently in compliance with these
regulations. In order to maintain its compliance, the Company has
made and will have to continue to make substantial expenditures in its efforts
to comply with the requirements of environmental and other
regulations. Further, the oil and gas regulatory environment could
change in ways that might substantially increase these
costs. Hydrocarbon-producing states regulate conservation practices
and the protection of correlative rights. These regulations affect
the Company’s operations and limit the quantity of hydrocarbons it may produce
and sell. In addition, at the federal level, the Federal Energy
Regulatory Commission regulates interstate transportation of natural gas under
the Natural Gas Act. Other regulated matters include marketing,
pricing, transportation and valuation of royalty payments.
The
Company has Significant Costs Related to Environmental Matters.
The Company’s operations are also
subject to numerous and frequently changing laws and regulations governing the
discharge of materials into the environment or otherwise relating to
environmental protection. The Company owns or leases, and has owned
or leased, properties that have been leased for the exploration and production
of oil and gas and these properties and the wastes disposed on these properties
may be subject to the Comprehensive Environmental Response, Compensation and
Liability Act, the Oil Pollution Act of 1990, the Resource Conservation and
Recovery Act, the Federal Water Pollution Control Act and similar state
laws. Under such laws, the Company could be required to remove or
remediate wastes or property contamination.
Laws and regulations protecting the
environment have generally become more stringent and, may in some cases, impose
“strict liability” for environmental damage. Strict liability means
that the Company may be held liable for damage without regard to whether it was
negligent or otherwise at fault. Environmental laws and regulations
may expose the Company to liability for the conduct of or
conditions
27
caused by
others or for acts that were in compliance with all applicable laws at the time
they were performed. Failure to comply with these laws and
regulations may result in the imposition of administrative, civil and criminal
penalties.
The Company’s ability to conduct
continued operations is subject to satisfying applicable regulatory and
permitting controls. The Company’s current permits and authorizations
and ability to get future permits and authorizations may be susceptible, on a
going forward basis, to increased scrutiny, greater complexity resulting in
increased cost or delays in receiving appropriate authorizations.
Insurance
Does Not Cover All Risks.
Exploration for and production of oil
and natural gas and the Company’s transportation and other activities can be
hazardous, involving unforeseen occurrences such as blowouts, fires and loss of
well control, which can result in damage to or destruction of wells or
production facilities, injury to persons, loss of life or damage to property or
to the environment. Although the Company maintains insurance against
certain losses or liabilities arising from its operations in accordance with
customary industry practices and in amounts that management believes to be
prudent, insurance is not available to the Company against all operational
risks.
The
Company’s Methane Extraction from Non-conventional Reserves Operations Involve
Substantial Cost and are Subject to Various Economic, Operational, and
Regulatory Risks.
The Company’s operations in projects
involving the extraction of methane gas from non-conventional reserves such as
landfill gas streams, require investment of substantial capital and are subject
to the risks typically associated with capital intensive operations, including
risks associated with the availability of financing for required equipment,
constructions schedules, air and water environmental permitting, and locating
transportation facilities and customers for the products produced from those
operations which may delay or prevent startup of such projects. After
startup of commercial operations, the presence of unanticipated pressures or
irregularities in constituents of the raw materials used in such projects from
time to time, miscalculations or accidents may cause the Company’s project
activities to be unsuccessful. Although the technologies to be
utilized in such projects is believed to be effective and economical, there are
operational risks in the use of such technologies in the combination to be
utilized by the Company as a result of both the combination of technologies and
the early stages of commercial development and use of such technologies for
methane extraction from non-conventional sources such as those to be used by the
Company. This risk could result in total or partial loss of the
Company’s investment in such projects. The economic risks of such
projects include the marketing risks resulting from price volatility of the
methane gas produced from such projects, which is similar to the price
volatility of natural gas. These projects are also subject to the
risk that the products manufactured nay not be accepted for transportation in
common carrier gas transportation facilities although the products meet
specified requirements for such transportation, or may be accepted on such terms
that reduce the returns of such projects to the Company. These
projects are also subject to the risk that the product manufactured may not be
accepted by purchasers thereof from time to time and the viability of such
projects would be dependent upon the Company’s ability to locate a replacement
market for physical delivery of the gas produced from the project.
28
The
Company Faces Significant Competition with Respect to Acquisitions or
Personnel.
The oil and gas business is highly
competitive. In seeking any suitable oil and gas properties for
acquisition, or drilling rig operators and related personnel and equipment, the
Company is a small entity with limited financial resources and may not be able
to compete with most other companies, including large oil and gas companies and
other independent operators with greater financial and technical resources and
longer history and experience in property acquisition and
operation.
The
Company Depends on Key Personnel, Whom it May Not be Able to Retain or
Recruit.
Jeffrey R. Bailey, the Company’s Chief
Executive Officer, other members of present management and certain Company
employees have substantial expertise in the areas of endeavor presently
conducted and to be engaged in by the Company. To the extent that
their services become unavailable, the Company would be required to retain other
qualified personnel. The Company does not know whether it would be
able to recruit and hire qualified persons upon acceptable terms. The
Company does not maintain “Key Person” insurance for any of the Company’s key
employees.
The
Company’s Operations are Subject to Changes in the General Economic
Conditions.
Virtually all of the Company’s
operations are subject to the risks and uncertainties of adverse changes in
general economic conditions, the outcome of potential legal or regulatory
proceedings, changes in environmental, tax, labor and other laws and regulations
to which the Company is subject, and the condition of the capital markets
utilized by the Company to finance its operations.
Being
a Public Company Significantly Increases the Company’s Administrative
Costs.
The Sarbanes-Oxley Act of 2002, as well
as rules subsequently implemented by the SEC and listing requirements
subsequently adopted by the NYSE Amex in response to Sarbanes-Oxley, have
required changes in corporate governance practices, internal control policies
and audit committee practices of public companies. Although the
Company is a relatively small public company these rules, regulations, and
requirements for the most part apply to the same extent as they apply to all
major publicly traded companies, As a result, they have significantly increased
the Company’s legal, financial, compliance and administrative costs, and have
made certain other activities more time consuming and costly, as well as
requiring substantial time and attention of our senior
management. The Company expects its continued compliance with these
and future rules and regulations to continue to require significant
resources. These rules and regulations also may make it more
difficult and more expensive for the Company to obtain director and officer
liability insurance in the future, and could make it more difficult for it to
attract and retain qualified members for the Company’s Board of Directors,
particularly to serve on its audit committee.
The
Company’s Chairman of the Board Beneficially Owns a Substantial Amount of the
Company’s Common Stock and Has Significant Influence over the Company’s
business.
Peter E. Salas, the Chairman of the
Company’s Board of Directors, is the sole shareholder and controlling person of
Dolphin Management, Inc. the general partner of Dolphin Offshore Partners, L.P.
(“Dolphin”) which is the Company’s largest shareholder. At December
31, 2009, Mr. Salas directly and through Dolphin owned 21,057,492 shares of the
Company’s common stock and had options granting
29
him the
right to acquire an additional 100,000 shares of common stock. His
ownership and voting control over approximately 35.6% of the Company’s common
stock gives him significant influence on the outcome of corporate transactions
or other matters submitted to the Board of Directors or shareholders for
approval, including mergers, consolidations and the sale of all or substantially
all of the Company’s assets.
Shares
Eligible for Future Sale May Depress the Company’s Stock Price.
As of March 12, 2010 the Company had
59,760,661 shares of common stock outstanding of which 21,667,282 shares were
held by affiliates. In addition, options to purchase 3,121,000 shares of
unissued common stock were granted under the Tengasco, Inc. Stock Incentive Plan
of which options to purchase 2,561,000 shares were vested at March 12,
2010.
On February 8, 2010, the Company issued
100,000 options to directors, which vested immediately. In addition,
80,000 of the 400,000 options issued to Mr. McInturff on February 1, 2008 also
vested.
All of the shares of common stock held
by affiliates are restricted or controlled securities under Rule 144 promulgated
under the Securities Act of 1933, as amended (the “Securities
Act”). The shares of the common stock issuable upon exercise of the
stock options have been registered under the Securities Act. Sales of
shares of common stock under Rule 144 or another exemption under the Securities
Act or pursuant to a registration statement could have a material adverse effect
on the price of the common stock and could impair the Company’s ability to raise
additional capital through the sale of equity securities.
Future
Issuance of Additional Shares of the Company’s Common Stock Could Cause Dilution
of Ownership Interest and Adversely Affect Stock Price.
The Company may in the future issue
previously authorized and unissued securities, resulting in the dilution of the
ownership interest of its current stockholders. The Company is
currently authorized to issue a total of 100,000,000 shares of common stock with
such rights as determined by the Board of Directors. Of that amount,
approximately 60 million shares have been issued. The potential issuance of the
approximately 40 million remaining authorized but unissued shares of common
stock may create downward pressure on the trading price of the Company’s common
stock. The Company may also issue additional shares of its common
stock or other securities that are convertible into or exercisable for common
stock for raising capital or other business purposes. Future sales of
substantial amounts of common stock, or the perception that sales could occur,
could have a material adverse effect on the price of the Company’s common
stock.
The
Company May Issue Shares of Preferred Stock with Greater Rights than Common
Stock.
Subject to the rules of the NYSE Amex,
the Company’s charter authorizes the Board of Directors to issue one or more
series of preferred stock and set the terms of the preferred stock without
seeking any further approval from holders of the Company’s common
stock. Any preferred stock that is issued may rank ahead of the
Company’s common stock in terms of dividends, priority and liquidation premiums
and may have greater voting rights than the Company’s common stock.
30
None.
Property
Location, Facilities, Size and Nature of Ownership.
General
The Company leases its principal
executive offices, consisting of approximately 6,134 square feet located at
11121 Kingston Pike, Suite E, Knoxville, Tennessee at a rental of $7,284 per
month and an office in Hays, Kansas at a rental of $750.00 per
month. The Company has leased office space in Houston, Texas for use
by Patrick McInturff, a Vice President of the Company, at a rental of
approximately $4,000 per month.
Although the Company does not pay taxes
on its Swan Creek leases, it pays ad valorem taxes on its Kansas
Properties. The Company has general liability insurance for its
Kansas and Tennessee Properties. As of December 31, 2009 the Company
does not have a production interest in Texas and Louisiana.
Kansas
Properties
The Kansas Properties as of December
31, 2009 contained 150 leases totaling approximately 22,400 gross
acres in the vicinity of Hays, Kansas. The decrease in the total
volume of acreage of the Company’s Kansas Properties from 30,251 acres at the
end of 2008 is primarily due to the Company’s evaluation and release of acreage
deemed uneconomical. In 2009, the Company continued to focus on
retaining properties with geologic value. Many of these leases are
still in effect because they are being held by production. These
leases provide for a royalty of 12.5%. Some wells are subject to an
overriding royalty interest from 0.5% to 9%. The Company maintains a
100% working interest in most of its older wells and any undrilled acreage in
Kansas. The terms for most of the Company’s newer leases in Kansas
are from three to five years.
During 2009, the Company drilled 1
gross well, the Albers #2 SWD, in which the Company has a 100% working
interest.
Kansas as a whole is of
major significance to the Company. The majority of the Company’s
current reserve value, current production, revenue, and future development
objectives are centered in the Company’s ongoing interests in
Kansas. By using 3-D seismic evaluation on existing locations owned
by the Company in Kansas, the Company has added and continues to add proven
direct offset locations. Breaking down the Company’s assets in Kansas
into individual leases produces no apparent stand out leases that appear to be
stand-alone principal properties. As a whole, however, our collective
central Kansas holdings (see map below) are of major significance and as a group
the most materially important segment of the Company as demonstrated by the
following facts during the year ending December 31, 2009:
Kansas
accounted for 91% of the Company’s revenue (i.e. $8.9 million of $9.7 million)
and 92% of the Company’s total production.
31
The map
below indicates the location of the 10 counties in Kansas in which the Company
had production as of December 31, 2009.
Tennessee
Properties
The Company’s Swan Creek leases are on
approximately 8,300 gross acres in Hancock and Claiborne Counties in
Tennessee. At this time all of the Company’s Tennessee production is
from Hancock County.
Reserve
and Production Summary
The
following tables indicate the county breakdown of 2009 production and reserve
values as of December 31, 2009. From a review of the tables below, it is
apparent that none of the Company’s leases on a standalone basis are
significant, but must all be viewed as a whole to appreciate their significance
to the company’s operations.
32
Production
by Area
|
Area
|
Gross
Production
MBOE
|
Average
Net
Revenue
Interest
|
Percentage
of Total
Oil
Production
|
|
Rooks
County, KS
|
136.8
|
0.760244
|
58%
|
|
Trego
County, KS
|
28.0
|
0.820411
|
12%
|
|
Ellis
County, KS
|
12.3
|
0.820133
|
5%
|
|
Graham
County, KS
|
9.0
|
0.870513
|
4%
|
|
Russell
County, KS
|
8.1
|
0.848400
|
3%
|
|
Barton
County, KS
|
7.0
|
0.814310
|
3%
|
|
Pawnee
County, KS
|
6.0
|
0.765704
|
3%
|
|
Rush
County, KS
|
4.4
|
0.845971
|
2%
|
|
Osborne
County, KS
|
2.9
|
0.626262
|
1%
|
|
Stafford
County, KS
|
2.2
|
0.827089
|
1%
|
|
Total
KS
|
216.7
|
92%
|
|
|
Hancock
County, TN
|
18.7
|
0.728298
|
8%
|
|
Total
|
235.4
|
100%
|
33
Discounted
Reserve Value by Area (in thousands)
|
Area
|
Proved
Developed
|
Proved
Undeveloped
|
Proved
Reserves
|
%
of
Total
|
|
Rooks
County, KS
|
$12,654
|
$4,220
|
$16,874
|
60%
|
|
Trego
County, KS
|
1,862
|
1,780
|
3,642
|
13%
|
|
Ellis
County, KS
|
1,877
|
-
|
1,877
|
7%
|
|
Barton
County, KS
|
822
|
635
|
1,457
|
5%
|
|
Graham
County, KS
|
1,076
|
332
|
1,408
|
5%
|
|
Rush
County, KS
|
646
|
-
|
646
|
2%
|
|
Stafford
County, KS
|
410
|
123
|
533
|
2%
|
|
Russell
County, KS
|
418
|
-
|
418
|
2%
|
|
Pawnee
County, KS
|
292
|
118
|
410
|
1%
|
|
Osborne
County, KS
|
155
|
95
|
250
|
1%
|
|
Total
KS
|
20,212
|
7,303
|
27,515
|
98%
|
|
Hancock
County, TN
|
672
|
-
|
672
|
2%
|
|
Total
|
$20,884
|
$7,303
|
$28,187
|
100%
|
Reserve Analyses
The Company’s estimated total net
proved reserves of oil and natural gas as of December 31, 2009 and 2008, and the
present values of estimated future net revenues attributable to those reserves
as of those dates, are presented in following tables. All of the Company’s
reserves were located in the United States. These estimates were prepared by
LaRoche Petroleum Consultants, Ltd. (“LaRoche”) of Dallas, Texas, and
are part of their reserve reports on the Company’s oil and gas
properties. LaRoche and its employees and its registered petroleum
engineers have no interest in the Company and performed those services at their
standard rates. LaRoche’s estimates were based on a review of
geologic, economic, ownership, and engineering data provided to them by the
Company. In accordance with SEC regulations, no price or cost
escalation or reduction was considered.
34
Total
Proved Reserves as of December 31, 2009
|
Producing
|
Non
Producing
|
Undeveloped
|
Total
|
|
|
Natural
gas (MMcf)
|
115.9
|
-
|
-
|
115.9
|
|
Oil
(MBbls)
|
1,340.4
|
238.4
|
694.4
|
2,273.2
|
|
Total
proved reserves (MBOE)
|
1,359.7
|
238.4
|
694.4
|
2,292.5
|
|
Standardized
measure of discounted
future
net cash flow
(in
thousands)
|
$15,699
|
$5,185
|
$7,303
|
$28,187
|
Total
Proved Reserves as of December 31, 2008
|
Producing
|
Non-producing
|
Undeveloped
|
Total
|
|
|
Natural
gas (MMcf)
|
907.3
|
2.9
|
-
|
910.2
|
|
Oil
(MBbl)
|
1,240.0
|
7.7
|
-
|
1,247.7
|
|
Total
proved reserves (MBOE)
|
1,391.2
|
8.2
|
-
|
1,399.4
|
|
Standardized
measure of discounted
future
net cash flow
(in
thousands)
|
$10,134
|
$159
|
-
|
$10,293
|
In December 2008, the SEC adopted new
rules related to “Modernization of Oil and Gas Reporting” which the Company
adopted for the year ended December 31, 2009. Per this rule, the
Company’s proved reserves as of December 31, 2009 are measured by using
commodity prices based on the twelve month unweighted arithmetic average of the
first day of the month price for the period January through December
2009. The Company’s proved reserves as of December 31, 2008 were
measured by using prices as of December 31, 2008. Under the SEC’s
final rule, prior period reserves were not restated. These respective prices are
held constant in accordance with SEC guidelines for the life of the wells
included in the reserve reports but are adjusted by lease for energy content,
quality, transportation, compression and gathering fees, and regional price
differentials. The oil and natural gas prices after basis adjustments
used in our December 31, 2009 reserve valuation were $53.81 per Bbl and $4.61
per Mcf. The oil and natural gas prices after basis adjustments used in our
December 31, 2008 reserve valuation were $33.96 per Bbl and $7.76 per
Mcf. The $19.85 per Bbl increase in oil price was the primary factor
in the increased 2009 reserve volumes and values as compared to 2008
levels. (Refer to Note 23, Supplemental Oil and Gas Information,
Standardized Measure of Discounted Future Net Cash Flows for additional reserve
information.)
35
The prices used in calculating the
estimated future net revenue attributable to proved reserves do not reflect
market prices for natural gas and oil production sold subsequent to December 31,
2009. There can be no assurance that all of the estimated proved
reserves will be produced and sold at the assumed
prices. Accordingly, the foregoing prices should not be interpreted
as a prediction of future prices.
In substance, the LaRoche Report used
estimates of oil and gas reserves based upon standard petroleum engineering
methods which include production data, decline curve analysis, volumetric
calculations, pressure history, analogy, various correlations and technical
factors. Information for this purpose was obtained from owners of
interests in the areas involved, state regulatory agencies, commercial services,
outside operators and files of LaRoche. The net reserve values in the
Report were adjusted to take into account the working interests that have been
sold by the Company in various wells.
Management has established, and is
responsible for, internal controls designed to provide reasonable assurance that
the estimates of Proved Reserves are computed and reported in accordance with
SEC rules and regulations as well as with established industry
practices. Management works closely with LaRoche to ensure accuracy
of the data provided to LaRoche. On a semi-annual basis, management
and staff meet with LaRoche to review properties and discuss assumptions to be
used in the calculation of reserves.
Production
The following tables summarize for the
past three fiscal years the volumes of oil and gas produced, the Company’s
operating costs and the Company’s average sales prices for its oil and
gas. The information includes volumes produced to royalty interest or
other parties’ working interest.
|
Kansas
|
|||||
|
Years
Ended December 31,
|
Production
|
Cost
of Production
(per
BOE)
|
Average
Sales Price
|
||
|
Oil
(Bbl)
|
Gas
(Mcf)
|
Oil
(Bbl)
|
Gas
(Per
Mcf)
|
||
|
2009
|
217,000
|
-
|
$14.61
|
$54.48
|
-
|
|
2008
|
231,598
|
-
|
$17.21
|
$92.69
|
-
|
|
2007
|
178,311
|
-
|
$16.97
|
$66.42
|
-
|
36
|
Tennessee
|
|||||
|
Years
Ended December 31,
|
Production
|
Cost
of Production
(per
BOE)
|
Average
Sales Price
|
||
|
Oil
(Bbl)
|
Gas
(Mcf)
|
Oil
(Bbl)
|
Gas
(Per
Mcf)
|
||
|
2009
|
5,750
|
78,000
|
$24.60
|
$54.87
|
$3.99
|
|
2008
|
6,396
|
104,043
|
$22.56
|
$88.20
|
$9.10
|
|
2007
|
6,877
|
117,129
|
$26.42
|
$64.81
|
$6.86
|
Average sales price for 2008 and 2007
noted in the two tables above have been changed from prior filings to reflect
actual average sales prices.
Oil
and Gas Drilling Activities
Kansas
In 2009, the Company drilled 1 SWD well
in Kansas.
The results of the wells drilled in
Kansas in 2009 are set out in the following table. The Company has a
100% working interest in the well.
|
Name
of Well
|
Date
Completed
|
Cumulative
Production (Bbl)
|
|
Albers
#2
|
11/2010
|
n/a-
SWD
|
The
Company continues to pursue incremental production increases where possible in
the older wells, by using recompletion techniques to enhance production from
currently producing intervals.
Tennessee
In 2009 the Company did not drill any
new wells in the Swan Creek Field. The Company believes that drilling
new gas wells in the Swan Creek Field itself will not contribute to achieving
any significant increase in daily gas production totals from the Field. As a
result, the Company does not have any plans at the present time to drill any new
gas wells in the Swan Creek Field.
37
Gross
and Net Wells
The following tables set forth the
fiscal years ending December 21, 2007, 2008 and 2009 the number of gross and net
development wells drilled by the Company. The term gross wells means
the total number of wells in which the Company owns an interest, while the term
net wells means the sum of the fractional working interest the Company owns in
the gross wells.
|
For
Years Ending December 31,
|
||||||
|
2009
|
2008
|
2007
|
||||
|
Kansas
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|
Productive
Wells
|
-
|
-
|
9
|
7.725
|
10
|
4.0
|
|
Dry
Holes
|
-
|
-
|
3
|
2.625
|
6
|
5.25
|
|
Salt
Water Disposal
|
1
|
1
|
-
|
-
|
-
|
-
|
Productive
Wells
The following table sets forth
information regarding the number of productive wells in which the Company held a
working interest as of December 31, 2009. Productive wells are either
producing wells or wells capable of commercial production although currently
shut-in. One or more completions in the same bore hole are counted as
one well.
|
Gas
|
Oil
|
|||
|
Gross
|
Net
|
Gross
|
Net
|
|
|
Kansas
|
-
|
-
|
213
|
181
|
|
Tennessee
|
21
|
16
|
4
|
4
|
|
Total
|
21
|
16
|
217
|
185
|
38
Developed
and Undeveloped Oil and Gas Acreage
As of December 31, 2009 the Company
owned working interests in the following developed and undeveloped oil and gas
acreage. Net acres refer to the Company’s interest less the interest
of royalty and other working interest owners.
|
Developed
|
Undeveloped
|
|||
|
Gross
Acres
|
Net
Acres
|
Gross
Acres
|
Net
Acres
|
|
|
Kansas
|
14,921
|
12,130
|
7,450
|
6,333
|
|
Tennessee
|
3,120
|
2,370
|
5,192
|
4,543
|
|
Total
|
18,041
|
14,500
|
12,642
|
10,876
|
The Company is not a party to any
pending material legal proceeding. To the knowledge of
management, no federal, state, or local governmental agency is presently
contemplating any proceeding against the Company, which would have a result
materially adverse to the Company. To the knowledge of management, no
director, executive officer or affiliate of the Company or owner of record or
beneficially of more than 5% of the Company’s common stock is a party adverse to
the Company or has a material interest adverse to the Company in any
proceeding.
|
ITEM
5.
|
MARKET
FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
PURCHASES OF EQUITY SECURITIES
|
39
|
|
Market
Information
|
The Company’s common stock is listed on
the NYSE Amex exchange under the symbol TGC. The Company’s common
stock was previously listed under the symbol TGC on the American Stock Exchange
until its acquisition by NYSE in October 2008. The range of high and
low closing prices for shares of common stock of the Company as reported on the
NYSE Amex during the fiscal years ended December 31, 2009 and December 31, 2008
are set forth below.
|
High
|
Low
|
|
|
For
the Quarters Ending
|
||
|
March
31, 2009
|
$0.76
|
$0.40
|
|
June
30, 2009
|
0.75
|
0.45
|
|
September
30, 2009
|
0.61
|
0.46
|
|
December
31, 2009
|
0.65
|
0.43
|
|
March
31, 2008
|
$.0.68
|
$0.51
|
|
June
30, 2008
|
2.67
|
0.56
|
|
September
30, 2008
|
2.99
|
0.94
|
|
December
31, 2008
|
1.01
|
0.48
|
|
|
Holders
|
As of March 12, 2010 the number of
shareholders of record of the Company’s common stock was 319 and management
believes that there are approximately 8,790 beneficial owners of the Company’s
common stock.
|
|
Dividends
|
The Company did not pay any dividends
with respect to the Company’s common stock in 2009 and has no present plans to
declare any further dividends with respect to its common stock.
|
|
Recent
Sales of Unregistered Securities
|
During
the fourth quarter of fiscal 2009, the Company did not sell or issue any
unregistered securities. Any unregistered equity securities that were
sold or issued by the Company during the first three quarters of fiscal 2009
were previously reported in Reports filed by the Company with the
SEC.
40
|
|
Purchases
of Equity Securities by the Company and Affiliated
Purchasers
|
Neither
the Company nor any of its affiliates repurchased any of the Company’s equity
securities during 2009.
|
|
Equity
Compensation Plan Information
|
See Item
12, “Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matter” for information regarding the Company’s equity compensation
plans.
The following selected financial data
have been derived from the Company’s financial statements, and should be read in
conjunction with those financial statements, including the related footnotes.
(In thousands, except per
share data)
Year
Ended December 31,
|
2009
|
2008
|
2007
|
2006
|
2005
|
|
|
Income
Statement Data:
|
|||||
|
Oil
and Gas Revenues
|
$ 9,711
|
$ 15,570
|
$ 9,300
|
$ 8,896
|
$ 7,068
|
|
Production
Cost and Taxes
|
5,315
|
5,888
|
4,323
|
3,287
|
3,046
|
|
General
and Administrative
|
1,731
|
1,863
|
1,417
|
1,293
|
1,323
|
|
Interest
Expense
|
634
|
608
|
333
|
169
|
473
|
|
Net
Income (Loss)
|
(2,018)
|
170
|
3,510
|
2,141
|
1,088
|
|
Net
Income (Loss) Attributable to Common Stockholders
|
(2,018)
|
170
|
3,510
|
2,141
|
1,088
|
|
Net
Income (Loss) Attributable to
Common
Stockholders Per Share
|
$ (0.03)
|
$ 0.00
|
$ 0.06
|
$ 0.04
|
$ 0.02
|
41
As of
December 31,
|
2009
|
2008
|
2007
|
2006
|
2005
|
|
|
Balance
Sheet Data:
|
|||||
|
Working
Capital Surplus (
Deficit
)
|
$ 260
|
$ 646
|
$ 2,473
|
$ 873
|
$
(1,335)
|
|
Oil
and Gas Properties, Net
|
12,360
|
14,142
|
16,940
|
12,704
|
9,676
|
|
Pipeline
Facilities, Net
|
12,397
|
12,380
|
12,917
|
13,461
|
13,994
|
|
Total
Assets
|
41,174
|
42,447
|
38,011
|
28,454
|
25,909
|
|
Long-Term
Debt
|
10,062
|
10,052
|
4,316
|
2,731
|
118
|
|
Stockholders’
Equity
|
$ 26,843
|
$ 28,576
|
$ 28,103
|
$ 24,420
|
$ 21,961
|
No cash
dividends had been declared or paid by the Company for the periods presented in
the above tables.
Results
of Operations
The Company reported a net loss to
holders of common stock of $2.0 million or $0.03 per share in 2009 compared to a
net income of $0.2 million or $0.00 per share in 2008 and compared to a net
income of $3.5 million or $0.06 per share in 2007.
The Company realized revenues of $9.7
million in 2009 compared to $15.6 million in 2008 and $9.4 million in
2007. Revenues decreased $5.9 million from 2008 primarily due to a
decrease in oil prices in Kansas as prices averaged $54.48 in 2009 compared to
$92.69 in 2008. The average price received for Kansas oil sales in
2007 was $66.42.
Gas prices received for sales of gas
from the Swan Creek Field averaged $3.99 per Mcf in 2009, $9.10 per Mcf in 2008
and $6.86 per Mcf in 2007. Oil prices received for sales of oil from
the Swan Creek field averaged $54.87 per barrel in 2009, $80.20 per barrel in
2008 and $64.81 in 2007.
42
Production costs and taxes in 2009
decreased to $5.3 million from $5.9 million in 2008 and was $4.3 million in
2007.
Depletion, depreciation, and
amortization for 2009 was $2.6 million, an increase from $2.2 million in 2008
and $1.6 million in 2007. The increase in 2009 over 2008 levels is primarily due
to a $10.7 million increase in future development cost association with the
proved reserves, partially offset by a 893 MBOE increase in
reserves.
The Company’s general and
administrative cost was $1.7 million in 2009, $1.9 million in 2008 and 1.4
million in 2007. The 2009, 2008 and 2007 cost included non-cash
charges related to stock options of $ 0.2 million, $0.2 million, and $0.1
million respectively.
Professional fees were $0.3 million in
2009 and 2008 and $0.2 million in 2007. This increase in 2008 was due to the
Company commencing its review of its internal controls over its financial
reporting.
The
Company’s public relation cost was $50,000 for 2009, compared to $41,000 for
2008 and $22,000 for 2007.
Interest
expense was $0.6 million in 2009 and 2008 and $0.3 million in 2007. The increase
in interest expense in 2009 and 2008 relates to increased borrowings from the
Sovereign credit facility.
During 2009, the Company recorded a
noncash unrealized loss on derivatives of $1.3 million or $0.02 per
share. This loss was based on the fair value of the oil derivative
agreement entered into in July 2009. (See Note 12 Derivatives and
Note 13 Fair Value Measurement for additional information related to the
derivative transaction and the valuation of this transaction.)
During 2008, the Company recorded an
$11.6 million non-cash ceiling test writedown of its oil and gas
properties. This writedown resulted from a significant reduction of
the Company’s proved reserve value as of December 31, 2008 due to low year end
oil prices.
The Company recorded a deferred tax
asset of $0.2 million in 2009 relating to the Company’s net operating loss carry
forwards and $5.2 million in 2008 with $1.6 million recognized as income tax
expense.
Liquidity
and Capital Resources
On June 29, 2006, the Company closed on
a $50 million revolving senior credit facility between the Company and Citibank
Texas, N.A. (“Citibank”). Under the facility, loans and letters of
credit were available to the Company on a revolving basis in an amount
outstanding not to exceed the lesser of $50 million or the borrowing base in
effect from time to time.
On December 17, 2007, Citibank assigned
the Company’s revolving credit facility with Citibank to Sovereign Bank as
requested by the Company. Under the facility as assigned to
Sovereign, loans and letters of credit are available to the Company on a
revolving basis in an amount outstanding not to exceed the lesser of $20 million
or the Company’s borrowing base in effect from time to time. The
Sovereign facility is secured by substantially all of the Company’s producing
and non-producing oil and gas properties and pipeline and the Company’s methane
assets. The Company’s initial borrowing base with Sovereign was set
at $7.0 million.
43
On June 2, 2008, the Company entered
into an amendment to its credit facility with Sovereign whereby the Company’s
borrowing base was increased by the Bank as a result of its review of the
Company’s currently owned producing properties. The borrowing base
was raised to $11 million effective June 2, 2008. The amendment also
set the interest rate to the greater of prime plus 0.25% or 6% per annum. The
Company had previously utilized about $4.2 million of the facility, leaving
approximately $6.8 million available for use by the Company upon this borrowing
base increase.
The
Company used $5.35 million of the then available $6.8 million for the purchase
of the Riffe Field properties in Kansas.
Effective February 5, 2009, the Company
amended its credit facility with Sovereign to provide for a monthly reduction of
the Bank’s commitment by $0.15 million per month for the five month period of
February through June 2009. This commitment reduction was not a cash
payment obligation of the Company but had the effect of reducing the Company’s
available borrowing base in monthly increments of $0.15 million under the
Sovereign facility.
On July 9, 2009 the Company’s borrowing
base was increased from $10.25 million to $11.0 million under the revolving
senior credit facility between the Company and Sovereign on the completion of
the regular semiannual borrowing base review. The $11.0 million
borrowing base was again made subject to a monthly available credit reduction of
$0.15 million per month beginning August 5, 2009.
As of September 30, 2009, the Company
was out of compliance on the Leverage Ratio and Interest Coverage Ratio
covenants under the Sovereign credit facility. The Company was in
compliance with the remaining financial covenants under the credit
facility. The noncompliance occurred primarily as a result of the low
commodity prices in the last quarter of 2008 and first and second quarters of
2009 that are included in the covenant compliance calculations. The
Company has received a waiver from Sovereign Bank for noncompliance of these
covenants for the quarter ended September 30, 2009. There can be no
assurances that Sovereign Bank will waive noncompliance of covenants should
future instances occur.
On February 23, 2010, the Company
entered into an amendment to its credit facility with Sovereign increasing the
borrowing base from $10.25 million to $11.0 million on completion of the
semiannual borrowing base review by Sovereign. The amendment also
reduced the monthly commitment reduction from $0.15 million to $0.1 million and
changed the maturity date to June 30, 2011. In addition, the
amendment modified the covenant compliance calculations. This
modification allowed the Company to exclude the first and second quarters of
2009. As of December 31, 2009, the Company was in compliance with all
covenants. The next borrowing base review will take place in June
2010.
The total borrowing by the Company
under the facility at December 31, 2008 and 2009 was $9.9 million.
Although the Company has not been
required as of the date of this Report to make any payment of principal to
Sovereign Bank under the borrowing base in effect at any time, the Company can
make no assurance that in view of the conditions in the national and world
economies, including the realistic possibility of low commodity prices being
received for the Company’s oil and gas production for extended periods, that
Sovereign may in the future make a redetermination of the Company’s
borrowing
44
base to a
point below the level of the installment or other payments to Sovereign in such
amount and at such times in order to reduce the principal of the Company’s
outstanding borrowing to a level not in excess of the borrowing base as it may
be redetermined.
During 2009 and 2008, the Company
remained focused on production and carefully used its cash flow and available
credit to do so. However, the Company can make no assurance that it
can continue normal operations indefinitely or for any specific period of time
in the event of extended periods of low commodity prices, such as occurred in
late 2008 and early 2009, or upon the occurrence of any significant downturn or
losses in operations. In such event, the Company may be required to
reduce costs of operations by various means, including not undertaking certain
maintenance or reworking operations that may be necessary to keep some of the
Company’s properties in production or to seek additional working capital by
additional means such as issuance of equity including preferred stock or such
other means as may be considered and authorized by the Company’s Board of
Directors from time to time.
Net cash provided by operating
activities was $1.7 million in 2009, $7.1 million in 2008 and $3.4 million in
2007. The reduction of cash provided by operating activities from
2008 to 2009 was primarily due to low product prices received during 2009 as
compared to 2008. Cash flow used for working capital was $0.2 million
in both 2009 and 2008. Cash provided by working capital was $0.2
million in 2007.
Net cash used in investing activities
was $1.5 million in 2009, $14.9 million in 2008, and $3.1 million in
2007. The decrease in 2009 was primarily due to a reduction in
investment of $11.0 million in oil and gas properties and $2.5 million in the
Methane Project from 2008 levels.
In 2009 no cash was provided by or used
in financing activities. Net cash provided by financing activities
was $5.8 million in 2008 and $1.6 million in 2007. The decrease in 2009 was due
to no new additional borrowings being made by the Company under the Sovereign
credit facility.
Critical
Accounting Policies
The Company prepares its Consolidated
Financial Statements in conformity with accounting principles generally accepted
in the United States of America, which require the Company to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosures of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
year. Actual results could differ from those
estimates. The Company considers the following policies to be the
most critical in understanding the judgments that are involved in preparing the
Company financial statements and the uncertainties that could impact the
Company’s results of operations, financial condition and cash
flows.
Revenue
Recognition
The Company recognizes revenues based
on actual volumes of oil and gas sold and delivered to its
customers. Natural gas meters are placed at the customer’s location
and usage is billed each month. Crude oil is stored and at the time
of delivery to the purchasers, revenues are recognized.
45
Full
Cost Method of Accounting
The Company follows the full cost
method of accounting for oil and gas property acquisition, exploration and
development activities. Under this method, all productive and
non-productive costs incurred in connection with the acquisition of, exploration
for and development of oil and gas reserves for each cost center are
capitalized. Capitalized costs include lease acquisitions, geological
and geophysical work, day rate rentals and costs of drilling, completing and
equipping oil and gas wells.
Costs,
however, associated with production and general corporate activities are
expensed in the period incurred. Interest costs related to unproved
properties and properties under development are also capitalized to oil and gas
properties. Gains or losses are recognized only upon sales or
dispositions of significant amounts of oil and gas reserves representing an
entire cost center. Proceeds from all other sales or dispositions are
treated as reductions to capitalized costs. The capitalized oil and
gas property, less accumulated depreciation, depletion and amortization and
related deferred income taxes, if any, are generally limited to an amount (the
ceiling limitation) equal to the sum of: (a) the present value of estimated
future net revenues computed by applying current prices in effect as of the
balance sheet date (with consideration of price changes only to the extent
provided by contractual arrangements) to estimated future production of proved
oil and gas reserves, less estimated future expenditures (based on current
costs) to be incurred in developing and producing the reserves using a discount
factor of 10% and assuming continuation of existing economic conditions; and (b)
the cost of investments in unevaluated properties excluded from the costs being
amortized. No ceiling write-downs were recorded in 2009 or 2007. However, in
2008 the Company incurred a ceiling limitation write-down in the amount of $11.6
million primarily due to the dramatically lower year-end oil prices in 2008 as
compared to 2007 and the resulting significant downward adjustment of the
Company’s estimated proved reserves. The effect of the ceiling write-down
resulted in the Company recording a net income in 2008 of $0.2
million.
Oil
and Gas Reserves/Depletion Depreciation and Amortization of Oil and Gas
Properties
The capitalized costs of oil and gas
properties, plus estimated future development costs relating to proved reserves
and estimated costs of plugging and abandonment, net of costs relating to proved
reserves and estimated costs of plugging and abandonment, net of estimated
salvage value, are amortized on the unit-of production method based on total
proved reserves. The costs of unproved properties are excluded from
amortization until the properties are evaluated, subject to an annual assessment
of whether impairment has occurred.
The Company’s proved oil and gas
reserves as of December 31, 2009 were determined by LaRoche Petroleum
Consultants, Ltd. Projecting the effects of commodity prices on
production, and timing of development expenditures includes many factors beyond
the Company’s control. The future estimates of net cash flows from
the Company’s proved reserves and their present value are based upon various
assumptions about future production levels, prices, and costs that may prove to
be incorrect over time. Any significant variance from assumptions
could result in the actual future net cash flows being materially different from
the estimates.
46
Asset
Retirement Obligations
The
Company’s asset retirement obligations relate to the plugging, dismantling and
removal of wells drilled to date. The Company follows the requirements of FASB
ASC 410, Asset Retirement Obligations and Environmental Obligations. Among other
things, FASB ASC 410 requires entities to record a liability and corresponding
increase in long-lived assets for the present value of material obligations
associated with the retirement of tangible long-lived assets. Over the passage
of time, accretion of the liability is recognized as an operating expense and
the capitalized cost is depleted over the estimated useful life of the related
asset. The Company’s asset retirement obligations relate primarily to
the plugging, dismantling and removal of wells drilled to date. The Company’s
calculation of Asset Retirement Obligation used a credit-adjusted risk free rate
of 12%, when the original liability was recognized. In 2009, the retirement
obligation for the Albers #2 SWD was recognized using the current credit
adjusted risk free rate of 8%. The Company used an estimated useful life of
wells ranging from 30-40 years and an estimated plugging and abandonment cost of
$5,000 per well. Management continues to periodically evaluate the
appropriateness of these assumptions.
Recent
Accounting Pronouncements
On
February 24, 2010, the FASB issued Accounting Standards Update (“ASU”) 2010-09,
effective immediately, which amended ASC Topic 855, Subsequent
Events. The amendment was made to address concerns about conflicts
with SEC guidance and other practice issues. Among the provisions of
the amendment, the FASB defined a new type of entity, termed an “SEC filer,”
which is an entity required to file with or furnish its financial statements to
the SEC. Entities other than registrants whose financial statements
are included in SEC filings (e.g., businesses or real estate operations acquired
or to be acquired, equity method investees, and entities whose securities
collateralize registered securities) are not SEC filers. While an SEC
filer is still required by U.S. GAAP to evaluate subsequent events through the
date its financial statements are issued , it is no longer required to disclose
in the financial statements that it has done so or the date through which
subsequent events have been evaluated. The Company does not believe
the changes have a material impact on our results of operations or financial
position.
In
January 2010, the FASB issued ASU No. 2010-06, Fair Value Measurements and
Disclosures (Topic 820): Improving Disclosures about Fair Value
Measurements. This update requires more robust disclosures about
valuation techniques and inputs to fair value measurement. The update
is effective for interim and annual reporting periods beginning after December
15, 2009. This update will have no material effect on the Company’s
consolidated financial statements.
In July
2009, the FASB issued ASC 855-10-50, Subsequent Events which requires an entity
to recognize in the financial statements the effects of all subsequent events
that provide additional evidence about conditions that existed at the date of
the balance sheet, including the estimates inherent in the process of the
financial statements. The final rules were effective for interim and annual
periods issued after June 15, 2009. The Company has adopted the
policy effective September, 2009. There was no material effect on the
Company’s consolidated financial statements as a result of the
adoption.
47
In June
2009, the FASB issued ASC 105, Codification which establishes FASB Codification
as the source of authoritative generally accepted accounting pronouncements
(“U.S. GAAP”) recognized by the FASB to be applied by nongovernmental entities.
The final rule was effective for interim and annual periods issued after
September 15, 2009. The Company has adopted the policy effective September 30,
2009. There was no material effect on the presentation of the Company’s
consolidated financial statements as a result of the adoption of ASC
105.
On
December 31, 2008, the SEC published the final rules and interpretations
updating its oil and gas reporting requirements (modernization of Oil and Gas
Reporting). In January 2010, the FASB released ASU 2010-03,
Extractive Activities- Oil and Gas (“Topic 932); Oil and Gas Reserve Estimation
and Disclosures aligning U.S. GAAP standards with the SEC’s new
rules. Many of the revisions are updates to definitions in the
existing oil and gas rules to make them consistent with the petroleum resource
management system, which is a widely accepted standard for the management of
petroleum resources that was developed by several industry
organizations.
Key
revisions include: (a) changes to the pricing used to estimate reserves
utilizing a 12-month average price rather than a single day spot price which
eliminates the ability to utilize subsequent prices to the end of a reporting
period when the full cost ceiling was exceeded and subsequent pricing exceeds
pricing at the end of a reporting period, (b) the ability to include
nontraditional resources in reserves, (c) the use of new technology for
determining reserves, and (d) permitting disclosure of probable and possible
reserves. The SEC will require companies to comply with the amended
disclosure requirements for registration statements filed after January 1, 2010,
and for annual reports on Form 10-K for fiscal years ending on or after December
15, 2009. ASU 2010-03 is effective for annual periods ending on or
after December 31, 2009. Adoption of Topic 932 did not have a
material impact on the Company’s results of operations or financial
position.
In
September 2006, the FASB issued ASC 820, “Fair Value Measurements”, which
applies under most other accounting pronouncements that require or permit fair
value measurements. FASB ASC 820 provides a common definition of fair value as
the price that would be received to sell an asset or paid to transfer a
liability in a transaction between market participants. The new standard also
provides guidance on the methods used to measure fair value and requires
expanded disclosures related to fair value measurements. FASB ASC 820 had
originally been effective for financial statements issued for fiscal years
beginning after November 15, 2007, however the FASB has agreed on a one year
deferral for all non-financial assets and liabilities. The Company adopted FASB
ASC 820 effective January 1, 2008. Adoption of this statement did not have a
material impact on the Company’s financial condition, results of operations, and
cash flows.
48
Contractual
Obligations
The following table summarizes the
Company’s contractual obligations due by period as of December 31, 2009:
(in thousands)
|
Contractual
Obligations
|
Total
|
Less
than
1
year
|
1-3
years
|
|
Long-Term
Debt Obligations
(See
Note 9 Long Term Debt)
|
$ 10,181
|
$ 119
|
$ 10,062
|
|
Operating
Lease Obligations
(See
Note 10 Commitments and Contingencies)
|
262
|
58
|
204
|
|
Total
|
$ 10,443
|
$ 177
|
$ 10,266
|
Commodity
Risk
The Company’s major market risk
exposure is in the pricing applicable to its oil and gas
production. Realized pricing is primarily driven by the prevailing
worldwide price for crude oil and spot prices applicable to natural gas
production. Historically, prices received for oil and gas production
have been volatile and unpredictable and price volatility is expected to
continue. Monthly oil price realizations range from a low of $29.87
per barrel to a high of $70.40 per barrel during 2009. Gas prices
realizations ranged from monthly low of $2.84 per Mcf to a monthly high of $6.16
per Mcf during the same period.
In order to help mitigate commodity
price risk, the Company has entered into a long term fixed price contract for
MMC gas sales. In addition the Company has entered into derivative
agreement on a specified number of barrels of oil that currently constitutes
about two-thirds of the Company’s daily production.
On August 27, 2009, the Company entered
into a five-year fixed price gas sales contract with Atmos Energy Marketing,
LLC, (“AEM”) in Houston, Texas, a nonregulated unit of Atmos Energy Corporation
(NYSE: ATO) for the sale of the methane component of landfill gas produced by
MMC at the Carter Valley Landfill. The agreement provides for the
sale of up to 600 MMBtu per day. The contract is effective beginning
with September 2009 gas production and ends July 31, 2014. The agreed
contract price of over $6 per MMBtu was a premium to the then current five-year
strip price for natural gas on the NYMEX futures market.
On July
28, 2009 the Company entered into a two-year agreement on crude oil pricing
applicable to a specified number of barrels of oil that currently constitutes
about two-thirds of the Company’s daily production. The agreement was
effective beginning August 1, 2009. The “costless collar” agreement has a $60.00
per barrel floor and $81.50 per barrel cap on a volume of 9,500 barrels per
month during the period from August 1, 2009 through December 31, 2010, and 7,375
barrels per month from January 1
49
through
July 31, 2011. The prices referenced in this agreement are WTI NYMEX. While the
agreement is based on WTI NYMEX prices, the Company receives a price based on
Kansas Common plus bonus, which results in approximately $7 per barrel less than
current WTI NYMEX prices.
Under a
“costless collar” agreement, no payment would be made or received by the
Company, as long as the settlement price is between the floor price and cap
price (“within the collar”). However, if the settlement price is
above the cap, the Company would be required to pay the counterparty an amount
equal to the excess of the settlement price over the cap times the monthly
volumes hedged. Also, if the settlement price is below the floor, the
counterparty would be required to pay the Company the deficit of the settlement
price below the floor times the monthly volumes hedged.
This
agreement is primarily intended to help maintain and stabilize cash flow from
operations if lower oil prices return, while providing some upside if prices
increase above the cap. If lower oil prices return, this agreement
may help to maintain the Company’s production levels of crude oil by enabling
the company to perform some ongoing polymer or other workover treatments on
then-existing producing wells in Kansas.
Interest
Rate Risk
At December 31, 2009, the Company had
debt outstanding of approximately $10.2 million including, as of that date, $9.9
million owed on its credit facility with Sovereign Bank. The interest
rate on the credit facility is variable at a rate equal to the prime rate plus
0.25% with a floor of 6%. The Company’s remaining debt of $0.3
million has fixed interest rates ranging from 5.5% to 8.25%. As a
result, the Company annual interest cost in 2009 fluctuated based on short-term
interest rates on approximately 97% of its total debt outstanding at December
31, 2009. During 2009, the Company paid $0.6 million of interest on
the Sovereign line of credit. The impact on interest expense and the
Company’s cash flows of a 10 percent increase in the interest rate on the
Sovereign Bank credit facility would be approximately $0.1 million assuming
borrowed amounts under the credit facility remained at the same amount owed as
of December 31, 2009. The Company did not have any open derivative
contracts relating to interest rates at December 31, 2009.
Forward-Looking
Statements and Risk
Certain statements in this Report,
including statements of the future plans, objectives, and expected performance
of the Company, are forward-looking statements that are dependent upon certain
events, risks and uncertainties that may be outside the Company’s control, and
which would cause actual results to differ materially from those
anticipated. Some of these include, but are not limited to, the
market prices of oil and gas, economic and competitive conditions, inflation
rates, legislative and regulatory changes, financial market conditions,
political and economic uncertainties of foreign governments, future business
decisions, and other uncertainties, all of which are difficult to
predict.
There are numerous uncertainties
inherent in projecting future rates of production and the timing of development
expenditures. The total amount or timing of actual future production
may vary significantly from estimates. The drilling of exploratory
wells can involve significant risks, including those related to timing, success
rates and cost overruns. Lease and rig availability, complex geology
and other factors can also affect these risks. Additionally,
fluctuations in oil and gas prices, or a prolonged
50
period of
low prices, may substantially adversely affect the Company financial position,
results of operations and cash flows.
The financial statements and
supplementary data commence on page F-1.
None
The Company’s Chief Executive Officer
and Chief Financial Officer, and other members of management team have evaluated
the effectiveness of the Company’s disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)). Based on such
evaluation, the Company’s Chief Executive Officer and Chief Financial Officer
have concluded that the Company’s disclosure controls and procedures, as of the
end of the period covered by this Report, were adequate and effective to provide
reasonable assurance that information required to be disclosed by the Company in
reports that is files or submits under the Exchange Act, is recorded, processed,
summarized and reported, within the time periods specified in the SEC’s rules
and forms.
The effectiveness of a system of
disclosure controls and procedures is subject to various inherent limitations,
including cost limitations, judgments used in decision making, assumptions about
the likelihood of future events, the soundness of internal controls, and
fraud. Due to such inherent limitations, there can be no assurance
that any system of disclosure controls and procedures will be successful in
preventing all errors or fraud, or in making all material information known in a
timely manner to the appropriate levels of management.
Managements
Report on Internal Control over Financial Reporting
Management of the Company is
responsible for establishing and maintaining adequate internal control over
financial reporting, as such term is defined in the Securities Exchange Act of
1934 Rules 13a-15(f) and 15d-15(f). Internal control over financial
reporting refers to the process designed by, or under the supervision of the
Company’s Chief Executive Officer and Chief Financial Officer, and effected by
the Company’s Board of Directors, management and other personnel, 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, and includes those policies and
procedures that:
|
|
·
|
Pertain
to the maintenance of records that, in reasonable detail, accurately and
fairly reflect the transactions and dispositions of the Company’s
assets;
|
|
|
·
|
Provide
reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted
accounting principles, and that
|
51
|
|
receipts
and expenditures are being made only in accordance with authorizations of
the Company’s management and directors;
and
|
|
|
·
|
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 company’s 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 into 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.
Under the supervision and with the
participation of the Company’s management, including the Chief Executive Officer
and the Chief Financial Officer, the Company’s management conducted an
evaluation of the effectiveness of the Company internal control over financial
reporting as of December 31, 2009. In making this assessment, the
Company’s management used the criteria set forth in the framework in “Internal
Control- Integrated- Framework” issued by the Committee of Sponsoring
Organizations of the Treadway Commission (“COSO”). Based on the evaluation
conducted under the framework in “Internal Control- Integrated Framework,”
issued by COSO the Company’s management concluded that the Company’s internal
control over financial reporting was effective as of December 31,
2009.
This annual report does not include an
attestation report of the Company’s registered public accounting firm regarding
internal control over financial reporting. Management’s report was
not subject to attestation by the Company’s registered public accounting firm
pursuant to temporary rules of the SEC that permit the Company to provide only
management’s report in this annual report.
Changes
in Internal Controls
During 2009, the Company engaged Risked
Revenue Energy Associates to assist Management in valuing the derivative
transaction. This valuation is then compared to counterparty’s market value for
validation purposes.
There have been no other changes to the
Company’s system of internal control over financial reporting during the year
ended December 31, 2009 that have materially affected, or are reasonably likely
to materially affect, the Company’s system of controls over financial
reporting.
As part of a continuing effort to
improve the Company’s business processes, Management is evaluating its internal
controls and may update certain controls to accommodate any modifications to its
business processes or accounting procedures.
The Company’s 2010 Annual Meeting of
Stockholders will be held on June 21,
2010
at 9:00 am at the Homewood Suites by Hilton, 10935 Turkey Drive, Knoxville,
Tennessee 37922.
52
Certain information required by Part
III of this Report is incorporated by reference from the Company’s definitive
proxy statement to be filed with the SEC in connection with the solicitation of
proxies for the Company’s 2010 Annual Meeting of Stockholders (the “Proxy
Statement”).
The information required by this Item
with respect to the Company’s directors is incorporated by reference to the
information in the section entitled “Proposal No. 1: Election of Directors” in
the Proxy Statement.
The information required by this Item
with respect to corporate governance regarding the Nominating Committee and
Audit Committee of the Board of Directors is incorporated by reference from the
section entitled “Board of Directors-Committees” in the Proxy
Statement.
The information required by this Item
with respect to disclosure of any known late filing or failure by an insider to
file a report required by Section 16 of the Exchange Act is incorporated by
reference to the information in the section entitled “Section 16(a) Beneficial
Ownership Reporting Compliance” in the Proxy Statement.
The information required by this item
with respect to the identification and background of the Company’s executive
officers and the Company’s Code of Ethics is set forth in Item 1 of this
Report.
The information required by this Item
is incorporated by reference from the information in the sections entitled
“Executive Compensation”, “Compensation/Stock Option Committee Interlocking and
Insider Participation” and “Compensation Committee Report” in the Proxy
Statement.
Except as set forth below, the
information required by this Item regarding security ownership of certain
beneficial owners and directors and officers is incorporated by reference from
the sections entitled “Voting Securities and Principal Holders” and “Beneficial
Ownership of Directors and Officers” in the Proxy Statement.
53
Equity
Compensation Plan Information
The following table sets forth
information regarding the Company’s equity compensation plans as of December 31,
2009.
|
Plan
Category
|
Number
of securities to be issued upon exercise of outstanding
options, warrants and rights(a)
|
Weighted-average
exercise price
of
outstanding, options, warrants and rights(b)
|
Number
of securities remaining available for future issuance under equity
compensation plans (excluding securities reflected in column (a))
(c)
|
|
|
Equity
compensation plans approved by security holders
|
3,021,000
|
$0.42
|
2,539,368
|
|
|
Equity
compensation plans not approved by security holders
3
|
-
|
n/a
|
-
|
|
|
Total
|
3,021,000
|
$0.42
|
2.539,368
|
The information required by this Item
as to transaction between the Company and related persons is incorporated by
reference from the section entitled “Certain Transactions” in the Proxy
Statement.
The information required by this Item
as to the independence of the Company’s directors and members of the committees
of the Company’s Board of Directors is incorporated by reference from the
section entitled “Board of Directors” and the subsections thereunder entitled
“Director Independence” and “Committees” set forth in “Proposal No.1: Election
of Directors” in the Proxy Statement.
The information required by this Item
is incorporated by reference from the information in the section entitled
“Proposal No. 2: Ratification of Selection of Rodefer Moss & Co. PLLC as
Independent Auditors” in the Proxy Statement.
3
Refers to Tengasco, Inc. Stock
Incentive Plan (the “Plan”) which was adopted to provide an incentive to key
employees, officers, directors and consultants of the Company and its present
and future subsidiary corporations, and to offer an additional inducement in
obtaining the services of such individuals. The Plan provides for the
grant to employees of the Company of “Incentive Stock Options” within the
meaning of Section 422 of the Internal Revenue Code of 1986, as amended,
Nonqualified Stock Options to outside Directors and consultants the Company and
stock appreciation rights. The Plan was approved by the Company’s shareholders
on June 26, 2001. Initially, the Plan provided for the issuance of a
maximum of 1,000,000 shares of the Company’s $.001 par value common
stock. Thereafter, the Company’s Board of Directors adopted and the
shareholders approved amendments to the Plan to increase the aggregate number of
shares that may be issued under the Plan to 7,000,000 shares. The
most recent amendment to the Plan increasing the number of shares that may be
issued under the Plan by 3,500,000
shares and extending the Plan for
another 10 years was approved by the Company Board of Directors on February 1,
2008 and approved by the Company’s shareholders at the Annual Meeting of
Stockholders held June 2, 2008
.
54
A. The
following documents are filed as part of this Report:
|
|
1.
|
Financial
Statements:
|
Consolidated
Balance Sheets
Consolidated
Income Statements
Consolidated
Statements of Stockholders Equity
Consolidated
Statements of Cash Flows
Notes to
Consolidated Financial Statements
|
|
2.
|
Financial
Schedules:
|
Schedules
have been omitted because the information required to be set forth therein is
not applicable or is included in the Consolidated Financial Statements or notes
thereto.
|
|
3.
|
Exhibits.
|
The
following exhibits are filed with, or incorporated by reference into this
Report:
Exhibit
Index
|
Exhibit Number
|
Description
|
|
3.1
|
Charter
(Incorporated by reference to Exhibit 3.7 to the registrant’s registration
statement on Form 10-SB filed August 7, 1997 (the “Form
10-SB”))
|
|
3.2
|
Articles
of Merger and Plan of Merger (taking into account the formation of the
Tennessee wholly-owned subsidiary for the purpose of changing the
Company’s domicile and effecting reverse split) (Incorporated by reference
to Exhibit 3.8 to the Form 10-SB)
|
|
3.3
|
Articles
of Amendment to the Charter dated June 24, 1998 (Incorporated by reference
to Exhibit 3.9 to the registrant’s annual report on Form 10-KSB filed
April 15, 1999 (the “1998 Form 10-KSB”))
|
|
3.4
|
Articles
of Amendment to the Charter dated October 30, 1998 (Incorporated by
reference to Exhibit 3.10 to the 1998 Form 10-KSB)
|
|
3.5
|
Articles
of Amendment to the Charter filed March 17, 2000 (Incorporated by
reference to Exhibit 3.11 to the registrant’s annual report on Form 10-KSB
filed April 14, 2000 (the “1999 Form
10-KSB”))
|
55
|
3.6
|
By-laws
(Incorporated by reference to Exhibit 3.2 to the Form
10-SB)
|
|
3.7
|
Amendment
and Restated By-laws dated May 19, 2005 (Incorporated by reference to the
registrant’s annual report on Form 10-K for the year ended December 31,
2005)
|
|
4.1
|
Form
of Rights Certificate Incorporated by reference to registrant’s statement
on Form S-1 filed February 13, 2004 Registration File No. 333-109784 (the
“Form S-1")
|
|
10.1
|
Natural
Gas Sales Agreement dated November 18, 1999 between Tengasco, Inc. and
Eastman Chemical Company (Incorporated by reference to Exhibit 10.10 to
the registrant’s current report on Form 8-K filed November 23,
1999)
|
|
10.2
|
Amendment
Agreement between Eastman Chemical Company and Tengasco, Inc. dated March
27, 2000 (Incorporated by reference to Exhibit 10.14 to the registrant’s
1999 Form 10-KSB)
|
|
10.3
|
Tengasco,
Inc. Incentive Stock Plan (Incorporated by reference to Exhibit 4.1 to the
registrant’s registration statement on Form S-8 filed October 26,
2000)
|
|
10.4
|
Amendment
to the Tengasco, Inc. Stock Incentive Plan dated May 19, 2005
(Incorporated by reference to Exhibit 4.2 to the registrant’s registration
statement on Form S-8 filed June 3, 2005)
|
|
10.5
|
Loan
and Security Agreement dated as of June 29, 2006 between Tengasco, Inc.
and Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.1 to the
registrant’s current report on Form 8-K dated June 29,
2006)
|
|
10.6
|
Subscription
Agreement of Hoactzin Partners, L.P. for the Company’s ten well drilling
program on its Kansas Properties dated August 3, 2007 (Incorporated by
reference to Exhibit 10.15 to the registrant’s Annual Report on Form 10-K
for the year ended December 31, 2007 filed March 31, 2008 [the “2007 Form
10-K”])..
|
|
10.7
|
Agreement
and Conveyance of Net Profits Interest dated September 17, 2007 between
Manufactured Methane Corporation as Grantor and Hoactzin Partners, LP as
Grantee (Incorporated by reference to Exhibit 10.16 to the 2007 Form
10-K).
|
|
10.8
|
Agreement
for Conditional Option for Exchange of Net Profits Interest for
Convertible Preferred Stock dated September 17, 2007 between Tengasco,
Inc., as Grantor and Hoactzin Partners, L.P., as Grantee (Incorporated by
reference to Exhibit 10.17 to the 2007 Form 10-K).
|
|
10.9
|
Assignment
of Notes and Liens Dated December 17, 2007 between Citibank, N.A., as
Assignor, Sovereign Bank, as Assignee and Tengasco, Inc., Tengasco Land
& Mineral Corporation and Tengasco Pipeline Corporation as
Debtors (Incorporated by reference to Exhibit 10.18 to the 2007
Form 10-K).
|
56
|
10.10
|
Management
Agreement dated December 18, 2007 between Tengasco, Inc. and Hoactzin
Partners, L.P. (Incorporated by reference to Exhibit 10.20 to
the 2007 Form 10-K).
|
|
10.11
|
Amendment
to the Tengasco, Inc. Stock Incentive Plan dated February 1, 2008, 2008
(Incorporated by reference to Exhibit 4.1 to the registrant’s registration
statement on Form S-8 filed June 3, 2008)
|
|
10.12
|
Assignment
of Leases from Black Diamond Oil, Inc. to Tengasco, Inc. (Incorporated by
reference to Exhibit 10.1 to the registrant’s Quarterly Report on Form
10-Q for the quarter ended June 30, 2008 filed on August 11,
2008).
|
|
10.13*
|
Energy
Option Transaction Confirmation Agreement (Put) between Tengasco, Inc. and
Macquarie Bank Limited dated September 17, 2009.
|
|
10.14*
|
Energy
Option Transaction Confirmation Agreement (Call) Amendment between
Tengasco, Inc. and Macquarie Bank Limited dated September 17,
2009.
|
|
14
|
Code
of Ethics (Incorporated by reference to Exhibit 14 to the registrant’s
annual report on Form 10-K filed March 30, 2004)
|
|
21
|
List
of subsidiaries (Incorporated by reference to Exhibit 21 to the 2007 Form
10-K).
|
|
23.1*
|
Consent
of LaRoche Petroleum Consultants, Ltd.
|
|
23.2*
|
Consent
of Risked Revenue Energy
Associates
|
|
31.1*
|
Certification
of Chief Executive Officer pursuant to Rule
13a-14(a)/15d-14
|
|
31.2*
|
Certification
of Chief Financial Officer pursuant to Rule
13a-14(a)/15d-14(a)
|
|
32.1*
|
Certification
of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
|
|
32.2*
|
Certification
of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
|
*
Exhibit filed
with this Report
57
Signatures
Pursuant
to the requirements of Section 13 or 15 (d) of the Securities and Exchange Act
of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
Dated:
March 31, 2010
Tengasco,
Inc.
(Registrant)
By:
s/ Jeffrey R.
Bailey
Jeffrey
R. Bailey,
Chief
Executive Officer
By:
s/ Michael J.
Rugen
Michael
J. Rugen,
Principal
Financial and Accounting Officer
Pursuant
to the requirements of the Securities and Exchange Act of 1934, this report has
been signed below by the following persons on behalf of the registrant and in
their capacities and on the dates indicated.
|
Signature
|
Title
|
Date
|
|
s/ Jeffrey R. Bailey
Jeffrey
R. Bailey
|
Director;
Chief Executive Officer
|
March
31,2010
|
|
s/ Matthew K. Behrent
Matthew
K. Behrent
|
Director
|
March
31, 2010
|
|
s/ John A. Clendening
John
A. Clendening
|
Director
|
March
31, 2010
|
|
s/Carlos P. Salas
Carlos
P. Salas
|
Director
|
March 31,
2010
|
|
s/ Peter E. Salas
Peter
E. Salas
|
Director
|
March
31, 2010
|
|
s/ Michael J. Rugen
Michael
J. Rugen
|
Principal
and Financial Accounting Officer
|
March
31, 2010
|
58
|
Tengasco,
Inc.
|
|
and
Subsidiaries
|
|
Consolidated
Financial Statements
Years
Ended December 31, 2009, 2008, and
2007
|
|
Report
of Independent Registered Public Accounting Firm
|
F-4
|
|
Consolidated
Financial Statements
Consolidated
Balance Sheets
|
F-5
|
|
Consolidated
Statements of Operations
|
F-7
|
|
Consolidated
Statements of Stockholders’ Equity
|
F-8
|
|
Consolidated
Statements of Cash Flows
|
F-9
|
|
Notes
to Consolidated Financial Statements
|
F-10
|
Report of
Independent Registered Public Accounting Firm
To the
Board of Directors and
Stockholders
of Tengasco, Inc.
We have
audited the accompanying consolidated balance sheets of Tengasco, Inc. (the
“Company”) as of December 31, 2009 and 2008, and the related consolidated
statements of operations, stockholders’ equity and cash flows for each of the
years in the three-year period ended December 31, 2009. The Company’s management
is responsible for these consolidated financial statements. Our responsibility
is to express an opinion on these consolidated financial statements based on our
audits.
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 financial
statements are free of material misstatement. The company was not required for
2009 to have, nor were we engaged to perform, an audit of its internal control
over financial reporting. Our audit included consideration of internal control
over financial reporting as a basis for designing audit procedures that are
appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the company’s internal control over financial
reporting. Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the 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 audits provide a
reasonable basis for our opinion.
In our
opinion, the consolidated financial statements referred to above present fairly,
in all material respects, the financial position of Tengasco, Inc. as of
December 31, 2009 and 2008, and the results of its operations and its cash flows
for each of the years in the three-year period ended December 31, 2009 in
conformity with accounting principles generally accepted in the United States of
America.
/s/
Rodefer Moss & Co, PLLC
Certified
Public Accountants
Knoxville,
Tennessee
March 26,
2010
F-4
Tengasco,
Inc. and Subsidiaries
Consolidated
Balance Sheets
(In
thousands, except per share and share data)
|
December
31,
|
||||
|
2009
|
2008
|
|||
|
Assets
|
||||
|
Current
|
||||
|
Cash
and cash equivalents
|
$
422
|
$ 245
|
||
|
Accounts
receivable
|
1,130
|
1,104
|
||
|
Participant
receivables
|
18
|
24
|
||
|
Inventory
|
581
|
476
|
||
|
Other
current assets
|
20
|
10
|
||
|
Total
current assets
|
2,171
|
1,859
|
||
|
Restricted
cash
|
121
|
121
|
||
|
Loan
fees
|
146
|
202
|
||
|
Oil
and gas properties, net (
full cost accounting
method
)
|
12,360
|
14,142
|
||
|
Pipeline
facilities, net
|
12,397
|
12,380
|
||
|
Methane
project, net
|
4,403
|
4,357
|
||
|
Other
property and equipment, net
|
306
|
285
|
||
|
Deferred
tax asset
|
9,270
|
9,101
|
||
|
Total
assets
|
$
41,174
|
$ 42,447
|
||
See
accompanying Notes to Consolidated Financial Statements
F-5
Tengasco,
Inc. and Subsidiaries
Consolidated
Balance Sheets
(In
thousands, except per share and share data)
|
December
31,
|
||||
|
2009
|
2008
|
|||
|
Liabilities
and Stockholders’ Equity
|
||||
|
Current
liabilities
|
||||
|
Current
maturities of long-term debt
|
$ 119
|
$ 75
|
||
|
Accounts
payable
|
742
|
701
|
||
|
Accrued liabilities
|
302
|
437
|
||
|
Unrealized
derivative liability
|
748
|
-
|
||
|
Total
current liabilities
|
1,911
|
1,213
|
||
|
Asset
retirement obligation
|
450
|
656
|
||
|
Deferred
conveyance oil and gas properties
|
490
|
1,097
|
||
|
Prepaid
revenues
|
853
|
853
|
||
|
Long
term debt, less current maturities
|
10,062
|
10,052
|
||
|
Unrealized
derivative liability
|
565
|
-
|
||
|
Total liabilities
|
14,331
|
13,871
|
||
|
Stockholders’
equity
|
||||
|
Common
stock, $.001 par value: authorized 100,000,000
|
||||
|
Shares;
59,760,661 and 59,350,661 shares issued and outstanding
|
60
|
59
|
||
|
Additional
paid in capital
|
55,277
|
54,993
|
||
|
Accumulated
deficit
|
(28,494)
|
(26,476)
|
||
|
Total
stockholders’ equity
|
26,843
|
28,576
|
||
|
Total
liabilities and stockholders’ equity
|
$41,174
|
$ 42,447
|
||
See
accompanying Notes to Consolidated Financial Statements
F-6
Tengasco,
Inc. and Subsidiaries
Consolidated
Statements of Operations
(In
thousands, except per share and share data)
|
Years
ended December 31,
|
||||||
|
2009
|
2008
|
2007
|
||||
|
Revenues
and other income
|
||||||
|
Oil
and gas revenues
|
$ 9,711
|
$ 15,570
|
$ 9,300
|
|||
|
Pipeline
transportation revenues
|
19
|
12
|
51
|
|||
|
Interest
income
|
1
|
19
|
17
|
|||
|
Total revenues and other
income
|
9,731
|
15,601
|
9,368
|
|||
|
Cost
and expenses
|
||||||
|
Production
costs and taxes
|
5,315
|
5,888
|
4,323
|
|||
|
Depreciation,
depletion, and amortization
|
2,571
|
2,160
|
1,631
|
|||
|
Ceiling
test impairment
|
-
|
11,608
|
-
|
|||
|
General
and administrative
|
1,731
|
1,863
|
1,417
|
|||
|
Professional
fees
|
304
|
264
|
232
|
|||
|
Public
relations
|
50
|
41
|
22
|
|||
|
Total cost and
expenses
|
9,971
|
21,824
|
7,625
|
|||
|
Net
income (loss) from operations
|
(240)
|
(6,223)
|
1,743
|
|||
|
Other
expense
|
||||||
|
Interest
expense
|
634
|
608
|
333
|
|||
|
Unrealized
loss on derivatives
|
1,313
|
-
|
-
|
|||
|
Total
other expense
|
1,947
|
608
|
333
|
|||
|
Deferred tax benefit
|
169
|
8,625
|
2,100
|
|||
|
Income
tax expense
|
-
|
(1,624)
|
-
|
|||
|
Net
income (loss)
|
$ (2,018)
|
$ 170
|
$ 3,510
|
|||
|
Net
income (loss) per share
|
||||||
|
Basic
|
$
(0.03)
|
$
0.00
|
$
0.06
|
|||
|
Fully
diluted
|
$
(0.03)
|
$ 0.00
|
$ 0.06
|
|||
|
Shares
used in computing earnings per share
|
||||||
|
Basic
|
59,408,990
|
59,248,446
|
59,117,176
|
|||
|
Diluted
|
59,408,990
|
61,492,446
|
60,827,224
|
|||
See
accompanying Notes to Consolidated Financial Statements
F-7
Tengasco,
Inc. and Subsidiaries
Consolidated
Statements of Stockholders’ Equity
(In
thousands, except per share and share data)
|
Common
Stock
|
Paid-in
Capital
|
Accumulated
Deficit
|
Total
|
||
|
Shares
|
Amount
|
||||
|
Balance,
December 31, 2006
|
59,003,284
|
$59
|
$54,517
|
$(30,156)
|
$24,420
|
|
Net
income
|
-
|
-
|
-
|
3,510
|
3,510
|
|
Options
and compensation expense
|
145,250
|
-
|
169
|
-
|
169
|
|
Commons
stock issued for exercise of warrants
|
7,216
|
-
|
3
|
-
|
3
|
|
Balance, December 31,
2007
|
59,155,750
|
$59
|
$54,690
|
$(26,646)
|
$28,103
|
|
Net
income
|
-
|
-
|
-
|
170
|
170
|
|
Options
and compensation expense
|
-
|
-
|
213
|
-
|
213
|
|
Shares
issued for compensation
|
30,000
|
-
|
18
|
-
|
18
|
|
Commons
stock issued for exercise of warrants
|
164,911
|
-
|
72
|
-
|
72
|
|
Balance,
December 31, 2008
|
59,350,661
|
$59
|
$54,993
|
$(26,476)
|
$28,576
|
|
Net
income/loss
|
-
|
-
|
-
|
(2,018)
|
(2,018)
|
|
Options
and compensation expense
|
-
|
-
|
174
|
-
|
174
|
|
Commons
stock issued for exercise of options
|
410,000
|
1
|
110
|
-
|
111
|
|
Balance, December 31,
2009
|
59,760,661
|
$60
|
$55,277
|
$(28,494)
|
$26,843
|
See
accompanying Notes to Consolidated Financial Statements
F-8
Tengasco,
Inc. and Subsidiaries
Consolidated
Statements of Cash Flows
(In
thousands)
|
Years
Ended December 31,
|
||||||
|
2009
|
2008
|
2007
|
||||
|
Operating
activities
|
||||||
|
Net
income (loss)
|
$ (2,018)
|
$ 170
|
$ 3,510
|
|||
|
Adjustments
to reconcile net income to net cash
|
||||||
|
Provided
by operating activities
|
||||||
|
Depletion,
depreciation, and amortization
|
2,571
|
2,160
|
1,631
|
|||
|
Accretion
on asset retirement obligation
|
48
|
155
|
71
|
|||
|
Ceiling
test impairment
|
-
|
11,608
|
-
|
|||
|
Loss
on sale of vehicles/equipment
|
-
|
10
|
5
|
|||
|
Compensation
and services paid in stock options
|
174
|
231
|
116
|
|||
|
Deferred
tax benefit
|
(169)
|
(7,001)
|
(2,100)
|
|||
|
Unrealized
loss on derivatives
|
1,313
|
-
|
-
|
|||
|
Changes
in assets and liabilities
|
||||||
|
Accounts
receivable
|
(26)
|
(47)
|
(337)
|
|||
|
Participant
receivables
|
6
|
25
|
(37)
|
|||
|
Other
current assets
|
(10)
|
-
|
-
|
|||
|
Inventory
|
(105)
|
(15)
|
90
|
|||
|
Accounts
payable
|
41
|
(203)
|
218
|
|||
|
Accrued
liabilities
|
(137)
|
67
|
332
|
|||
|
Settlement
on asset retirement obligations
|
-
|
(30)
|
(52)
|
|||
|
Net
cash provided by operating activities
|
1,688
|
7,130
|
3,447
|
|||
|
Investing
activities
|
||||||
|
Additions
to oil and gas properties
|
(1,020)
|
(11,965)
|
(5,191)
|
|||
|
Drilling
program portion of additional drilling
|
-
|
-
|
3,850
|
|||
|
Proceeds
from sale of oil and gas properties
|
142
|
-
|
-
|
|||
|
Net
additions to Methane Project
|
(184)
|
(2,707)
|
(1,650)
|
|||
|
Net additions to pipeline facilities
|
(418)
|
(7)
|
-
|
|||
|
Net
additions to other property & equipment
|
-
|
(189)
|
(155)
|
|||
|
Net
cash (used in) investing activities
|
(1,480)
|
(14,868)
|
(3,146)
|
|||
|
Financing
activities
|
||||||
|
Proceeds
from exercise of options/warrants
|
111
|
72
|
56
|
|||
|
Proceeds
from borrowings
|
-
|
5,889
|
1,696
|
|||
|
Loan
fees
|
-
|
(69)
|
(77)
|
|||
|
Repayment
of borrowings
|
(142)
|
(136)
|
(119)
|
|||
|
Net
cash provided by (used in) financing activities
|
(31)
|
5,756
|
1,556
|
|||
|
Net
change in cash and change equivalents
|
177
|
(1,982)
|
1,857
|
|||
|
Cash
and cash equivalents, beginning of period
|
245
|
2,227
|
370
|
|||
|
Cash
and cash equivalents, end of period
|
$ 422
|
$ 245
|
$ 2,227
|
|||
|
Supplemental
cash flow information:
|
||||||
|
Interest
paid
|
$ 634
|
$ 447
|
$ 262
|
|||
|
Supplemental
non-cash investing and financing activities:
|
||||||
|
Financed
Company vehicles
|
$ 196
|
-
|
-
|
|||
See
accompanying Notes to Consolidated Financial Statements
F-9
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
1.
Description of Business and Significant Accounting Policies
Tengasco,
Inc. is a Tennessee corporation (“Tengasco” or the “Company”).
The
Company is in the business of exploration and production of oil and natural
gas. The Company’s primary area of oil exploration and production is
in Kansas. The Company’s primary area of gas exploration and
production is the Swan Creek Field in Tennessee.
The
Company’s wholly-owned subsidiary, Tengasco Pipeline Corporation (“TPC”), owns
and operates a 65 mile intrastate pipeline which it constructed to transport
natural gas from the Company’s Swan Creek Field to customers in Kingsport,
Tennessee.
The
Company’s wholly-owned subsidiary, Manufactured Methane Corporation (“MMC”) owns
and operates treatment and delivery facilities using the latest developments in
available treatment technologies for the extraction of methane gas from
nonconventional sources for delivery through the nations existing natural gas
pipeline system, including the Company’s TPC pipeline system in Tennessee for
eventual sale to natural gas customers.
Principles
of Consolidation
The accompanying consolidated financial
statements are presented in accordance with U.S. generally accepted accounting
principles. The consolidated financial statements include the
accounts of the Company, and its wholly-owned subsidiaries after elimination of
all significant intercompany transactions and balances.
Use
of Estimates
The accompanying consolidated financial
statements are prepared in conformity with U.S. generally accepted accounting
principles which require management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting
period. The actual results could differ from those
estimates.
Revenue
Recognition
The Company uses the sales method of
accounting for oil and natural gas revenues. Under this method,
revenues are recognized based on actual volumes of oil and gas sold to
purchasers.
Cash
and Cash Equivalents
Cash and cash equivalents include
temporary cash investments with a maturity of ninety days or less at date of
purchase.
F-10
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
Inventory
Inventory consists of crude oil in
tanks and is carried at lower of cost or market value.
Oil
and Gas Properties
The Company follows the full cost
method of accounting for oil and gas property acquisition, exploration, and
development activities. Under this method, all costs incurred in
connection with acquisition, exploration and development of oil and gas reserves
are capitalized. Capitalized costs include lease acquisitions,
seismic surveys, drilling, completion, and estimated asset retirement costs. The
capitalized costs of oil and gas properties, plus estimated future development
costs relating to proved reserves and estimated asset retirement costs, which
are not already included net of estimated salvage value, are amortized on the
unit-of-production method based on total proved reserves. The Company has
determined its reserves based upon reserve reports provided by LaRoche Petroleum
Consultants Ltd. in 2009, 2008, and 2007. The costs of unproved properties are
excluded from amortization until the properties are evaluated, subject to an
annual assessment of whether impairment has occurred. The Company
currently has $0.1 million in unevaluated properties as of December 31,
2009. Proceeds from the sale of oil and gas properties are accounted
for as reductions to capitalized costs unless such sales cause a significant
change in the relationship between costs and the estimated value of proved
reserves, in which case a gain or loss is recognized.
At the end of each reporting period,
the Company performs a “ceiling test” on the value of the net capitalized cost
of oil and gas properties. This test compares the net capitalized cost
(capitalized cost of oil and gas properties, net of accumulated depreciation,
depletion and amortization and related deferred income taxes) to the present
value of estimated future net revenues from oil and gas properties using an
average price (arithmetic average of the beginning of month prices for the prior
12 months) discounted at 10% (ceiling). Prior to the year ending
December 31, 2009, the ceiling was calculated using the year end
price. If the net capitalized costs exceed this limit, the excess is
charged to earnings and may not be reversed in subsequent
periods. During 2008, the Company recorded an impairment of $11.6
million as a result of the year end December 31, 2008 ceiling test
analysis. No impairment was required for the years ended December 31,
2009 and 2007.
Asset
Retirement Obligation
We record the fair value of a liability
for a legal obligation to retire an asset in the period in which the liability
is incurred with an offsetting increase to oil and gas
properties. For oil and gas properties, this is the period in which
the well is drilled or acquired. A legal obligation is a liability
that a party is required to settle as a result of an existing law, statute,
ordinance or contract. Each period, we accrete the liability to its
then present value and depreciate the capitalized cost over the useful life of
the related asset.
F-11
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
Pipeline
Facilities
The pipeline was placed into service
upon its completion on March 8, 2001. The pipeline is being
depreciated over its estimated useful life of 30 years beginning at the time it
was placed in service.
Manufactured
Methane Facilities
The methane facilities were placed into
service on April 1, 2009. The methane facilities are being
depreciated over an estimated useful life of 13 years and 9 months beginning at
the time it was placed in service.
Other
Property and Equipment
Other property and equipment is carried
at cost. The Company provides for depreciation of other property and
equipment using the straight-line method over the estimated useful lives of the
assets which range from two to seven years.
Net gains or losses on other property
and equipment disposed of are included in operating income in the period in
which the transaction occurs.
Stock-Based
Compensation
The
Company accounts for stock-based compensation in accordance with FASB ASC 718
Compensation-Stock Compensation. ASC 718 requires all share-based
payments to employees to be recognized in our consolidated statements of
operations based on their estimated fair values. We recognize expense
on a straight line basis over the vesting period of the options. The Company
recorded compensation expense of $0.2 million in 2009 and 2008 and $0.1 million
in 2007.
Accounts
Receivable
Senior management reviews accounts
receivable on a monthly basis to determine if any receivables will potentially
be uncollectible. Based on the information available, the Company
believes no allowance for doubtful accounts as of December 31, 2009 and 2008 is
necessary. However, actual write-offs may occur.
Income
Taxes
The Company accounts for income taxes
using the “asset and liability method.” Accordingly, deferred tax
liabilities and assets are determined based on the temporary differences between
the financial reporting and tax bases of assets and liabilities, using enacted
tax rates in effect for the year in which the differences are expected to
reverse. Deferred tax assets arise primarily from net operating loss
carry-forwards. Management evaluates the likelihood of realization
for such assets at year end providing a valuation allowance for any such amounts
not likely to be recovered in future periods. The
Company
F-12
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
currently
has a net operating loss carry forward of $15.5 million.
As of December 31, 2008, the Company
also had a deferred tax asset totaling $3.9 million related to a ceiling test
write-down of $11.6 million. This deferred tax asset arose from
differences between the financial statement carrying value of the Company’s oil
and gas properties and their respective income tax bases (temporary differences)
after taking into consideration the reduced depletion expense from the ceiling
test write down. To assess the realization of deferred tax assets,
management considers whether it is more likely than not that some portion or all
of this deferred tax asset will be realized. The ultimate realization of
deferred tax assets is dependent upon the generation of future taxable income
during the periods in which those temporary differences become deductible.
Management considers the scheduled reversal of deferred tax liabilities,
projected future taxable income and tax planning strategies in making this
assessment. Management has determined that it is more likely
than not that all of this deferred tax asset will be realized. The
$3.9 million deferred tax asset related to the ceiling test write-down is in
addition to the deferred tax assets resulting from the Company’s net operating
loss carry-forwards. The total deferred tax asset at December 31, 2009 is $9.3
million.
Concentration
of Credit Risk
Financial instruments which potentially
subject the Company to concentrations of credit risk consist principally of cash
and accounts receivable. At December 31, 2009, such cash in banks is
in excess of the FDIC insurance limit. The Company’s primary business activities
include oil and gas sales to a limited number of customers in the states of
Kansas and Tennessee. The related trade receivables subject the
Company to a concentration of credit risk.
The Company sells a majority of its
crude oil primarily to one customer in Tennessee and two customers in
Kansas. Additionally, the Company is presently dependent upon a small
number of customers for the sale of gas from the Swan Creek
Field. Although management believes that customers could be replaced
in the ordinary course of business, if the present customers were to discontinue
business with the Company, it may have a significant adverse effect on the
Company’s projected results of operations.
Revenue from the top three purchasers
accounted for 85.1%, 10.5% and 3.1% of total oil and gas revenues for year ended
December 31, 2009. Revenue from the top three purchasers accounted
for 93.6%, 3.5% and 2.5% of total oil and gas revenues for the year ended
December 31, 2008. Revenue from the top three purchasers accounted
for 91.4%, 4.9% and 3.7% of total oil and gas revenues for the year ended
December 31, 2007.
F-13
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
Income
per Common Share
In accordance with FASB ASC 260,
Earnings Per Share, basic income per share is based on 59,408,990, 59,248,446
and 59,117,176 weighted average shares outstanding for the years ended December
31, 2009, 2008 and 2007, respectively. Diluted earnings per common share are
computed by dividing income available to common shareholders by the weighted
average number of shares of common stock outstanding during the period increased
to include the number of additional shares of common stock that would have been
outstanding if the dilutive potential shares of common stock had been
issued. The dilutive effect of outstanding options and warrants is
reflected in diluted earnings per share. The numbers of dilutive
shares outstanding were 2,244,000 and 1,710,048 for the years ended December 31,
2008 and 2007, respectively. Because the Company had a net loss for the year
ended December 31, 2009, dilutive potential shares of common stock are excluded
as they are anti-dilutive.
Fair
Value of Financial Instruments
Fair value of cash and cash
equivalents, investments and short term debt approximate their carrying value
due to the short period of time to maturity. Fair value of long term
debt is based on quoted market prices or pricing models using current market
rates, which approximate carrying value. (See Note 12 Fair Value
Measurement)
Derivative
Financial Instruments
The Company uses derivative instruments
to manage our exposure to commodity price risk on sales of oil
production. We do not enter into the derivative instruments for
speculative trading purposes. We present the fair value of our
derivative contracts on a net basis where the right to offset is provided for in
our counterparty agreements. (See Note 13 Derivatives)
Reclassifications
Certain prior year amounts have been
reclassified to conform to current year presentation with no effect on net
income.
2.
Recent Accounting Pronouncements
On
February 24, 2010, the FASB issued Accounting Standards Update (“ASU”) 2010-09,
effective immediately, which amended ASC Topic 855, Subsequent
Events. The amendment was made to address concerns about conflicts
with SEC guidance and other practice issues. Among the provisions of
the amendment, the FASB defined a new type of entity, termed an “SEC filer,”
which is an entity required to file with or furnish its financial statements to
the SEC. Entities other than registrants whose financial statements
are included in SEC filings (e.g., businesses or real estate operations acquired
or to be acquired, equity method investees, and entities whose securities
collateralize registered securities) are not SEC filers. While an SEC
filer is still required by U.S. GAAP to evaluate subsequent events through the
date its financial statements are issued , it is no longer required to disclose
in the financial statements that it has done so or the date through which
subsequent events have been evaluated. The Company does not believe
the changes have a material impact on our results of operations or financial
position.
F-14
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
In
January 2010, the FASB issued ASU 2010-06, “Fair Value Measurements and
Disclosures (Topic 820): Improving Disclosures about Fair Value
Measurements”. This update requires more robust disclosures about
valuation techniques and inputs to fair value measurements. The
update is effective for interim and annual reporting periods beginning after
December 15, 2009. This update will have no material effect on the
Company’s consolidated financial statements.
In July
2009, the FASB issued ASC 855-10-50, “Subsequent Events”, which requires an
entity to recognize in the financial statements the effects of all subsequent
events that provide additional evidence about conditions that existed at the
date of the balance sheet, including the estimates inherent in the preparation
of the financial statements. The final rules were effective for interim and
annual periods issued after June 15, 2009. The Company has adopted the policy
effective September, 2009. There was no material effect on the
Company’s consolidated financial statements as a result of the
adoption.
In June
2009, the FASB issued ASC 105, Codification which establishes FASB Codification
as the source of authoritative generally accepted accounting pronouncements
(“U.S. GAAP”) recognized by the FASB to be applied by nongovernmental entities.
The final rule was effective for interim and annual periods issued after
September 15, 2009. The Company has adopted the policy effective September 30,
2009. There was no material effect on the presentation of the Company’s
consolidated financial statements as a result of the adoption of ASC
105.
On
December 31, 2008, the SEC published the final rules and interpretations
updating its oil and gas reporting requirements (“Modernization of Oil and Gas
Reporting”). In January 2010, the FASB released ASU 2010-03,
Extractive Activities- Oil and Gas (“Topic 932); Oil and Gas Reserve Estimation
and Disclosures aligning U.S. GAAP standards with the SEC’s new
rules. Many of the revisions are updates to definitions in the
existing oil and gas rules to make them consistent with the petroleum resource
management system, which is a widely accepted standard for the management of
petroleum resources that was developed by several industry
organizations. Key revisions include: (a) changes to the pricing used
to estimate reserves utilizing a 12-month average price rather than a single day
spot price which eliminates the ability to utilize subsequent prices to the end
of a reporting period when the full cost ceiling was exceeded and subsequent
pricing exceeds pricing at the end of a reporting period, (b) the ability to
include nontraditional resources in reserves, (c) the use of new technology for
determining reserves, and (d) permitting disclosure of probable and possible
reserves. The SEC will require companies to comply with the amended
disclosure requirements for registration statements filed after January 1, 2010,
and for annual reports on Form 10-K for fiscal years ending on or after December
15, 2009. ASU 2010-03 is effective for annual periods ending on or
after December 31, 2009. Adoption of Topic 932 did not have a
material impact on the Company’s results of operations or financial
position.
F-15
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
In
September 2006, the FASB issued ASC 820, “Fair Value Measurements”, which
applies under most other accounting pronouncements that require or permit fair
value measurements. FASB ASC 820 provides a common definition of fair value as
the price that would be received to sell an asset or paid to transfer a
liability in a transaction between market participants. The new standard also
provides guidance on the methods used to measure fair value and requires
expanded disclosures related to fair value measurements. FASB ASC 820 had
originally been effective for financial statements issued for fiscal years
beginning after November 15, 2007, however the FASB has agreed on a one year
deferral for all non-financial assets and liabilities. The Company adopted FASB
ASC 820 effective January 1, 2008. Adoption of this statement did not
have a material impact on the Company’s financial condition, results of
operations, and cash flows.
3.
Related Party Transactions
On
September 17, 2007, the Company entered into a drilling program with Hoactzin
Partners, L.P. (“Hoactzin”) for ten wells consisting of approximately three
wildcat wells and seven developmental wells to be drilled on the Company’s
Kansas Properties (the “Ten Well Program”). Peter E. Salas, the Chairman of the
Board of Directors of the Company, is the controlling person of Hoactzin. He is
also the sole shareholder and controlling person of Dolphin Management, Inc. and
the general partner of Dolphin Offshore Partners, L.P., which is the Company’s
largest shareholder. Carlos P. Salas, a director of the Company, has an interest
in Hoactzin but is not a controlling person of Hoactzin. Under the terms of the
Ten Well Program, Hoactzin was to pay the Company $0.4 million for each well in
the Ten Well Program completed as a producing well and $0.25 million for each
well drilled that was non-productive. The terms of the Ten Well Program also
provide that Hoactzin will receive all the working interest in the ten wells in
the Program, but will pay an initial fee to the Company of 25% of its working
interest revenues net of operating expenses. This is referred to as a
management fee but, as defined, is in the nature of a net profits
interest. The fee paid to the Company by Hoactzin will increase to
85% of working interest revenues when and if net revenues received by Hoactzin
reach an agreed payout point of approximately 1.35 times Hoactzin’s purchase
price (the “Payout Point”) for its interest in the Ten Well
Program.
In March
2008, the Company drilled and completed the tenth and final well in the Ten Well
Program. Of the ten wells drilled, nine were completed as oil producers and are
currently producing approximately 61 barrels per day in total. Hoactzin paid a
total of $3.85 million (the “Purchase Price”) for its interest in the Ten Well
Program resulting in the Payout Point being determined as $5.2
million. The amount paid by Hoactzin for its interest in the Program
wells exceeded the Company’s actual drilling costs of approximately $2.8 million
for the ten wells by more than $1 million.
F-16
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
Although
production level of the Program wells will decline with time in accordance with
expected decline curves for these types of wells, based on the drilling results
of the wells in the Ten Well Program and the current price of oil, the Program
wells would be expected to reach the Payout Point in approximately four years
solely from the oil revenues from the wells. However, under the terms of the
Company’s agreement with Hoactzin, reaching the Payout Point may be accelerated
by operation of a second agreement by which Hoactzin will apply 75% of the net
proceeds it receives from a methane extraction project discussed below developed
by the Company’s wholly-owned subsidiary, Manufactured Methane Corporation
(“MMC”), to the Payout Point. Those methane project proceeds when applied may
result in the Payout Point being achieved sooner than the estimated four year
period based solely upon revenues from the Program wells.
On
September 17, 2007, Hoactzin, simultaneously with subscribing to participate in
the Ten Well Program, pursuant to an additional agreement with the Company was
conveyed a 75% net profits interest in the methane extraction project developed
by MMC at the Carter Valley landfill owned and operated by Republic Services in
Church Hill, Tennessee (the "Methane Project"). Revenues from the Project
received by Hoactzin will be applied towards the determination of the Payout
Point (as defined above) for the Ten Well Program. When the Payout
Point is reached from either the revenues from the wells drilled in the Ten Well
Program or the Methane Project or a combination thereof, Hoactzin’s net profits
interest in the Methane Project will decrease to a 7.5% net profits
interest.
On
September 17, 2007, the Company also entered into an additional agreement with
Hoactzin providing that if the Program and the Methane Project interest in
combination failed to return net revenues to Hoactzin equal to 25% of the
Purchase Price it paid for its interest in the Ten Well Program by December 31,
2009, then Hoactzin would have an option to exchange up to 20% of its net
profits interest in the Methane Project for convertible preferred stock to be
issued by the Company with a liquidation value equal to 20% of the Purchase
Price less the net proceeds received at the time of any exchange. At the time
the agreement was negotiated, the Company's forecast of the probable results of
the projects indicated that there was little risk that the option to acquire
preferred stock would ever arise, so the Company placed no significant value to
the preferred stock option. By December 31, 2009 the amount of net revenues
received by Hoactzin from the Ten Well Program has reduced the Company’s
obligation to Hoactzin for the amount of the funds it had advanced for the
Purchase Price from $3.85 million to $1.3 million. The conversion option would
be set at issuance of the preferred stock at the then twenty business day
trailing average closing price of Company stock on the NYSE Amex. Hoactzin has a
similar option each year after 2009 in which Hoactzin’s then-unrecovered
Purchase Price at the beginning of the year is not reduced 20% further by the
end of that year, using the same conversion option calculation at date of the
subsequent year’s issuance if any. The Company, however, may in any
year make a cash payment from any source in the amount required to prevent such
an exchange option for preferred stock from arising. In addition, the
conversion right is limited to no more than 19% of the outstanding common shares
of the Company.
F-17
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
In the
event Hoactzin’s 75% net profits interest in the Methane Project were fully
exchanged for preferred stock, by definition the reduction of that 75% interest
to a 7.5% net profits interest that was agreed to occur upon the receipt of
1.3547 of the Purchase Price by Hoactzin could not happen because the larger
percentage interest then exchanged, no longer exists to be
reduced. Accordingly, Hoactzin would retain no net profits interest
in the Methane Project after a full exchange of Hoactzin’s 75% net profits
interest for preferred stock.
Under
this exchange agreement, if no proceeds at all were received by Hoactzin through
2009 or in any year thereafter (i.e. a worst-case scenario already highly
unlikely in view of the success of the Program), then Hoactzin would
have an option to exchange 20% of its interest in the Methane Project in 2010
and each year thereafter for preferred stock with liquidation value of 100% of
the Purchase Price (not 135%) convertible at the trailing average price before
each year’s issuance of the preferred stock. The maximum number of
common shares into which all such preferred stock could be converted cannot be
calculated given the formulaic determination of conversion price based on future
stock price.
However,
revenues from the Ten Well Program have resulted in 61% of the Purchase Price
having already been reached. Accordingly, it is highly unlikely that any
requirement to issue preferred stock will arise in 2010 or any succeeding
years.
On
December 18, 2007, the Company entered into a Management Agreement with
Hoactzin. On that same date, the Company also entered into an
agreement with Charles Patrick McInturff employing him as a Vice-President of
the Company. Pursuant to the Management Agreement with Hoactzin, Mr.
McInturff’s duties while he is employed as Vice-President of the Company will
include the management on behalf of Hoactzin of its working interest in certain
oil and gas properties owned by Hoactzin and located in the onshore Texas Gulf
Coast, and offshore Texas and offshore Louisiana. As consideration
for the Company entering into the Management Agreement, Hoactzin has agreed that
it will be responsible to reimburse the Company for the payment of one-half of
Mr. McInturff’s salary, as well as certain other benefits he receives during his
employment by the Company. In further consideration for the Company’s
agreement to enter into the Management Agreement, Hoactzin has granted to the
Company an option to participate in up to a 15% working interest on a dollar for
dollar cost basis in any new drilling or work-over activities undertaken on
Hoactzin’s managed properties during the term of the Management
Agreement. The term of the Management Agreement is the earlier of the
date Hoactzin sells its interest in its managed properties or five
years.
4.
Deferred Conveyance/Prepaid Revenues
The
Company has adopted a deferred conveyance/prepaid revenues presentation of the
transactions between the Company and Hoactzin Partners, L.P. on September 17,
2007 to more clearly present the effects of the three-part transaction
consisting of the Ten Well Program, the Methane Project and a contingent
exchange option agreement.
F-18
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
To
reflect the deferred conveyance, the Company has allocated $0.9 million of the
$3.85 million Purchase Price paid by Hoactzin for its interest in the Ten Well
Program to the Methane Project, based on a relative fair value calculation of
the Methane Project’s portion of the projected payout stream of the combined two
projects as seen at the inception of the agreement, utilizing then current
prices and anticipated time periods when the Methane Project would come on
stream. The Ten Well Program at inception was $2.95 million and the
prepaid revenues were $0.9 million.
The
Company has established separate deferred conveyance and prepaid revenue
accounts for the Ten Well Program and the Methane Project. Release of
the deferred amounts to the Ten Well Program will be made as proceeds are
actually distributed to Hoactzin. Release will be made on the
respective proceeds only as to each project until either one or both satisfy the
threshold amount that removes the contingent equity exchange
option. The prepaid revenues will be released using the units of
production method.
The
reserve information for the parties’ respective Ten Well Program interests as of
December 31, 2009 is indicated in the table below. Reserve reports are obtained
annually and estimates related to those reports are updated upon receipt of the
report. These calculations were made using commodity prices
based on the twelve month arithmetic average of the first day of the month price
for the period January through December 2009 as required by SEC regulations. The
table below reflects eventual pay as occurring through the realization of
proceeds at prices used in the reserve report dated December 31, 2009 of
approximately $53.81 per barrel.
F-19
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
Reserve
Information for Ten Well Program Interest for the Year Ended December 31,
2009
|
Barrels
Attributable to Party’s Interest
MBbl
|
Future
Cash Flows Attributable to Party’s Interest
(in
thousands)
|
Present
Value of Future Cash Flows Attributable to Party’s Interest
(in
thousands)
|
|
|
Tengasco
|
29.5
|
$706.1
|
$431.6
|
|
Hoactzin
Partners, L.P.
|
88.5
|
$2,118.3
|
$1,294.8
|
As of
year-end 2009, the original invested amount of $3.85 million has been reduced to
$1.3 million. This amount is the total of the deferred conveyance of
$0.5 million and the prepaid revenue account of $0.85 million. Hoactzin’s first
right to convert its invested amount of $3.85 million into preferred stock is
only exercisable to the extent Hoactzin’s investment has not been reduced by 25%
by the end of 2009. For each year after 2010 in which Hoactzin’s
then-unrecovered invested amount at the beginning of the year is not reduced 20%
further by the end of that year, Hoactzin has a similar
option. Consequently, Hoactzin is already precluded by these results
from any possibility of exercising its contingent option under the exchange
agreement to convert into preferred stock until the year ending December 31,
2011 at the earliest. All of the $2.5 million paid from the program has been
from the Ten Well Program and the deferred conveyance account has been reduced
from $3 million to $0.5 million.
As noted,
in future periods, the Company anticipates that this Hoactzin investment will
continue to be further reduced by sales of oil produced from the Ten Well
Program, or methane produced from the Methane Project, or
both. From inception of the project through December 31, 2010,
the Company projects that the original $3.85 million Purchase Price will be
reduced by 81% to $0.7 million. For the year ending December 31,
2011, the amount is projected to be reduced to zero. As a result, Hoactzin’s
contingent option to exchange for preferred stock would fully terminate without
any further annual reduction tests. These projections are based upon
expected production levels from the oil wells in the Ten Well Program and an
estimated 400 Mcf/day production from the Methane Project using $40 oil prices
and a $5 per Mcf gas sales price net of operating expenses. The
projection will vary with the actual oil and gas prices, production volumes, and
expenses experienced in 2010 and 2011. Based on these projections the
Company considers that it is a remote contingency that any right of Hoactzin to
elect to exchange its Methane Project interest for Company preferred stock will
ever arise. However, in the event of a conversion of Hoactzin’s Methane Project
interest for Company preferred stock as set out in limited circumstances in the
applicable agreement, and which the Company anticipates is highly unlikely,
there would be a debit to the deferred conveyance liability and the prepaid
revenue account for both the Ten Well Program and Methane Project because no
contingent option would remain on such a conversion and the Company would
simultaneously credit preferred stock in the converted amount.
F-20
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
In the
event of the termination of the option to convert into preferred stock because
the $3.85 million has been repaid from the Ten Well Program or Methane Project
or both, the applicable oil and gas properties will be deemed to have been fully
conveyed to Hoactzin and the Ten Well Program account, will be credited and the
liability will be removed, as at this time the price received for the program
will be fixed and determinable.
5.
Oil and Gas Properties
The
following table sets forth information concerning the Company’s oil and gas
properties:
(in
thousands):
|
December
31,
|
||
|
2009
|
2008
|
|
|
Oil
and gas properties, at cost
|
$ 24,182
|
$
23,031
|
|
Unevaluated
properties
|
109
|
1,243
|
|
Accumulated
depreciation, depletion and amortization
|
(11,931)
|
(10,132)
|
|
Oil
and gas properties, net
|
$ 12,360
|
$ 14,142
|
During
the years ended December 31, 2009, 2008, and 2007, the Company recorded
depletion expense of $1.8 million, $1.4 million and $0.8 million,
respectively.
During
2009, the Company received $142,000 in proceeds for the disposal of the Deutsch,
Howlier, Landers, and Pfeiffer properties. (See Note 23, Supplemental Oil and
Gas Information, Standardized Measure of Discounted Net Cash Flows for
information regarding the reserve value impact of these sales.)
6.
Pipeline Facilities
In 1996,
the Company began construction of a 65-mile pipeline connecting the Swan Creek
development project to a gas purchaser and enabling the Company to develop gas
transportation business opportunities in the future. Phase I, a
30-mile portion of the pipeline, was completed in 1998. Phase II of
the pipeline, the remaining 35 miles, was completed in March
2001. .
The
estimated useful life of the pipeline for depreciation purposes is 30
years. The Company recorded depreciation expense of $0.4 million, for
the year ended December 31, 2009, and $0.5 million for the years ended December
31, 2008, and 2007. Gross costs were $16.8 million and $16.3 million
and accumulated depreciation was $4.4 million and $4.0 million at December 31,
2009 and 2008, respectively.
F-21
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
7.
Manufactured Methane Facility
The methane facility was placed in
service on April 1, 2009, and is being depreciated over an estimated useful life
of 13 years and 9 months. At December 31, 2009 gross costs were $4.5
million. Depreciation expense during 2009 was $0.1
million.
8.
Other Property and Equipment
Other
property and equipment consisted of the following:
(in thousands)
|
December
31,
|
Depreciable
Life
|
2009
|
2008
|
|
Machinery
and equipment
|
5-7
yrs
|
$ 831
|
$ 831
|
|
Vehicles
|
2-5
yrs
|
561
|
556
|
|
Other
|
5
yrs
|
64
|
64
|
|
Total
|
1,456
|
1,451
|
|
|
Less
accumulated depreciation
|
(1,150)
|
(1,166)
|
|
|
Other
property and equipment-net
|
$ 306
|
$ 285
|
The
Company uses the straight-line method of depreciation for other property and
equipment
9.
Long-Term Debt
Long-term
debt to unrelated entities consisted of the following:
(in thousands)
|
December
31,
|
2009
|
2008
|
|
Note payable to a financial institution, with interest only payment until maturity. (See Note 19 Bank Debt) |
$ 9,900
|
$ 9,900
|
|
Installment notes bearing interest at the rate of 5.5% to 8.25% per annum collateralized by vehicles with monthly payments including interest, insurance and maintenance of approximately $20,000 |
281
|
227
|
|
Total long-term
debt
|
10,181
|
10,127
|
|
Current
maturities
|
119
|
75
|
|
Long-term
debt, less current maturities
|
$10,062
|
$10,052
|
10.
Commitments and Contingencies
The
Company is a party to lawsuits in the ordinary course of its
business. The Company does not believe that it is probable that the
outcome of any individual action will have a material adverse effect, or that it
is likely that adverse outcomes of individually insignificant actions will be
significant enough, in number or magnitude, to have in the aggregate a material
adverse effect on its financial statements.
F-22
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
On March
1, 2010, the Company entered into a lease for office space in Knoxville,
Tennessee. The term of the lease is 41 months (five of which are free) and
expires on July 31, 2013. The payment on this lease is $7,284 per
month.
Future
non-cancellable commitments related to this lease are as follows (in
thousands):
|
Year
|
|
|
2010
|
$ 58
|
|
2011
|
73
|
|
2012
|
80
|
|
2013
|
51
|
|
$262
|
Office
rent expense for each of the three years ended December 31, 2009, 2008 and 2007
was $0.1 million.
1
1. Black Diamond
Purchase
Effective
as of July 1, 2008, the Company purchased from Black Diamond Oil, Inc. 80
barrels per day of oil producing properties and related leases in Rooks County,
Kansas for $5.35 million. The Company also acquired producing oil
wells and salt water disposal wells, equipment, and the underlying working
interests in leases comprising what is known as the Riffe field that had been
owned by Black Diamond for many years. The purchase price was paid
primarily from borrowings under its credit facility with Sovereign Bank and from
company cash on hand. Following the purchase, the Company has
borrowed a total of $9.9 million under its credit facility.
12.
Fair Value Measurements
FASB ASC
820, “Fair Value Measurements and Disclosures”, establishes a framework for
measuring fair value. That framework provides a fair value hierarchy that
prioritizes the inputs to valuation techniques used to measure fair value. The
hierarchy gives the highest priority to unadjusted quoted prices in active
markers for identical assets and liabilities (Level 1 measurements) and the
lowest priority to unobservable inputs (Level 3 measurements). The three levels
of the fair value hierarchy under FASB ASC 820 are described as
follows:
Level
1 Inputs to the valuation methodology are unadjusted quoted prices
for identical assets or liabilities in active markets. Level 2 Inputs
to the valuation methodology include:
F-23
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
|
|
·
|
Quoted
prices for similar assets or liabilities in active markets; Quoted prices
for identical or similar assets or liabilities in inactive
markets;
|
|
|
·
|
Inputs
other than quoted prices that are observable for the asset or
liability;
|
|
|
·
|
Inputs
that are derived principally from or corroborated by observable market
data by correlation or other means.
|
If the
asset or liability has a specified (contractual) term, the Level 2 input must be
observable for substantially the full term of the asset or
liability
Level
3 Inputs to the valuation methodology are unobservable and
significant to the fair value measurement.
The
assets or liabilities fair value measurement level within the fair value
hierarchy is based on the lowest level of any input that is significant to the
fair value measurement. Valuation techniques used need to maximize the use of
observable inputs and minimize the use of unobservable inputs. Following is a
description of the valuation methodologies used for assets measured at fair
value.
The
methods described above may produce a fair value calculation that may not be
indicative of net realizable value or reflective of future fair values.
Furthermore, although the Company believes its valuation methods are appropriate
and consistent with other market participants, the use of different
methodologies or assumptions to determine the fair value of certain financial
instruments could result in a different fair value measurement at the reporting
date.
The
following table sets forth by level, within the fair value hierarchy, the
Company’s liabilities at fair value as of December 31, 2009. (in
thousands)
|
Level
1
|
Level
2
|
Level
3
|
|||
|
Derivative
liabilities
|
-
|
$1,313
|
-
|
||
|
Total
liabilities at fair value
|
$
-
|
$1,313
|
$-
|
||
13.
Derivatives
On July
28, 2009 the Company entered into a two-year agreement on crude oil pricing
applicable to a specified number of barrels of oil that currently constitutes
about two-thirds of the Company’s daily production.
F-24
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
The
agreement was effective beginning August 1, 2009. The “costless collar”
agreement has a $60.00 per barrel floor an $81.50 per barrel cap on a volume of
9,500 barrels per month during the period from August 1, 2009 through December
31, 2010, and 7,375 barrels per month from January 1 through July 31, 2011. The
prices referenced in this agreement are WTI NYMEX. While the agreement is based
on WTI NYMEX prices, the Company receives a price based on Kansas Common plus
bonus, which results in approximately $7 per barrel less than current WTI NYMEX
prices. The average price per barrel received by the Company in the first
quarter 2009 was $35.74, $52.52 for the second quarter 2009, $60.96 for the
third quarter 2009 and $68.69 for the fourth quarter 2009.
Under a
“costless collar” agreement, no payment would be made or received by the
Company, as long as the settlement price is between the floor price and cap
price (“within the collar”). However, if the settlement price is
above the cap, the Company would be required to pay the counterparty an amount
equal to the excess of the settlement price over the cap times the monthly
volumes hedged. Also, if the settlement price is below the floor, the
counterparty would be required to pay the Company the deficit of the settlement
price below the floor times the monthly volumes hedged.
This
agreement is primarily intended to help maintain and stabilize cash flow from
operations if lower oil prices return, while providing at least some upside if
prices increase above the cap. If lower oil prices return, this
agreement may help to maintain the Company’s production levels of crude oil by
enabling the company to perform some ongoing polymer or other workover
treatments on then existing producing wells in Kansas.
As of
December 31, 2009, our open forward positions on our outstanding “costless
collar” agreements, all of which are with Macquarie Bank Limited (“Macquarie”),
were as follows:
|
Period
|
Monthly
Volume
|
Total
Volume
|
Floor/Cap
NYMEX
|
Fair
Value at
December
31, 2009
(in
thousands)
|
|
Oil
(Bbls)
|
Oil
(Bbls)
|
$
per Bbl
|
||
|
1
st
Qtr 2010
|
9,500
|
28,500
|
$60.00-$81.50
|
$ (78)
|
|
2
nd
Qtr 2010
|
9,500
|
28,500
|
$60.00-$81.50
|
$ (174)
|
|
3
rd
Qtr 2010
|
9,500
|
28,500
|
$60.00-$81.50
|
$ (228)
|
|
4
th
Qtr 2010
|
9,500
|
28,500
|
$60.00-$81.50
|
$ (268)
|
|
1
st
Qtr 2011
|
7,375
|
22,125
|
$60.00-$81.50
|
$
(231)
|
|
2
nd
Qtr 2011
|
7,375
|
22,125
|
$60.00-$81.50
|
$ (248)
|
|
3
rd
Qtr 2011
|
7,375
|
7,375
|
$60.00-$81.50
|
$
(86)
|
|
$ (1,313)
|
||||
|
Current
Liability
|
$ (748)
|
|||
|
Non-current
Liability
|
$ (565)
|
F-25
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
The Fair
Value amounts noted in the above table are based on valuations provided by
Macquarie. Management has engaged Risked Revenue Energy Associates to
perform an independent valuation which confirmed the amounts provided by
Macquarie. The Company records changes in the unrealized derivative
asset or liability as an unrealized gain or loss in the Consolidated Statements
of Operations.
Through
December 31, 2009, no settlement payment has been required under the agreement
as WTI NYMEX prices through that date remained within the collar.
14.
Asset Retirement Obligation
The
Company follows the requirements of FASB ASC 410, “Asset Retirement Obligations
and Environmental Obligations”. Among other things, FASB ASC 410
requires entities to record a liability and corresponding increase in long-lived
assets for the present value of material obligations associated with the
retirement of tangible long-lived assets. Over the passage of time, accretion of
the liability is recognized as an operating expense and the capitalized cost is
depleted over the estimated useful life of the related asset. The
Company’s asset retirement obligations relate primarily to the plugging,
dismantling and removal of wells drilled to date. The Company’s calculation of
Asset Retirement Obligation used a credit-adjusted risk free rate of 12%, when
the original liability was recognized. In 2009, the retirement obligation for
the Albers #2 SWD was recognized using the current credit adjusted risk free
rate of 8%. The Company used an estimated useful life of wells ranging from
30-40 years and an estimated plugging and abandonment cost of $5,000 per well.
Management continues to periodically evaluate the appropriateness of these
assumptions.
The
following is a roll-forward of activity impacting the asset retirement
obligation for the years ended December 31, 2008 and 2009:
(in thousands):
|
Balance
December 31, 2007
|
$ 531
|
|
Accretion
expense
|
155
|
|
Liabilities
settled
|
(30)
|
|
Balance
December 31, 2008
|
$ 656
|
|
Accretion
expense
|
48
|
|
Liabilities
incurred
|
2
|
|
Revisions
in estimated liabilities
|
(256)
|
|
Balance
December 31, 2009
|
$ 450
|
The
liabilities incurred relate to the Albers #2 SWD. The revisions in estimated
liabilities resulted primarily from reducing the estimated plugging and
abandonment costs for the Kansas properties from $10,000 per well to $5,000 per
well.
F-26
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
15. Stock
Options
In
October 2000, the Company approved a Stock Incentive Plan. The Plan
is effective for a ten-year period commencing on October 25, 2000 and ending on
October 24, 2010. The aggregate number of shares of Common Stock as
to which options and Stock Appreciation Rights may be granted to participants
under the Plan shall not exceed 7,000,000. The most recent amendment to the Plan
increasing the number of shares that may be issued under the Plan by 3,500,000
shares and extending the Plan for another ten years was approved by the
Company’s Board of Directors on February 1, 2008 and approved by the Company’s
shareholders at the Annual Meeting of Stockholders held on June 2,
2008. Options are not transferable, are exercisable for 3 months
after voluntary resignation from the Company, and terminate immediately upon
involuntary termination from the Company. The purchase price of
shares subject to this Plan shall be determined at the time the options are
granted, but are not permitted to be less than 85% of the fair market value of
such shares on the date of grant. Furthermore, a participant in the
Plan may not, immediately prior to the grant of an Incentive Stock Option
hereunder, own stock in the Company representing more than ten percent of the
total voting power of all classes of stock of the Company unless the per share
option price specified by the Board for the Incentive Stock Options granted such
a participant is at least 110% of the fair market value of the Company’s stock
on the date of grant and such option, by its terms, is not exercisable after the
expiration of 5 years from the date such stock option is granted.
Stock
option activity in 2009, 2008, and 2007 is summarized below:
|
2009
|
2008
|
2007
|
||||
|
Shares
|
Weighted
Average
Exercise
Price
|
Shares
|
Weighted
Average
Exercise
Price
|
Shares
|
Weighted
Average
Exercise
Price
|
|
|
Outstanding,
beginning
of year
|
2,931,000
|
$0.38
|
2,441,000
|
$0.30
|
2,596,000
|
$0.31
|
|
Granted
|
500,000
|
$0.54
|
500,000
|
$0.74
|
-
|
-
|
|
Exercised
|
(410,000)
|
$0.27
|
(10,000)
|
$0.27
|
(126,000)
|
$0.42
|
|
Expired/cancelled
|
-
|
-
|
-
|
-
|
(29,000)
|
$0.64
|
|
Outstanding
end of year
|
3,021,000
|
$0.42
|
2,931,000
|
$0.38
|
2,441,000
|
$0.30
|
F-27
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
The
following table summarizes information about stock options outstanding and
exercisable at December 31, 2009:
|
Weighted
Average Exercise Price
|
Options
Outstanding
(shares)
|
Weighted
Average Remaining Contractual Life (years)
|
Options
Exercisable
(shares)
|
|
$0.27
|
1,831,000
|
0.3
|
1,831,000
|
|
$0.58
|
110,000
|
1.1
|
110,000
|
|
$0.81
|
80,000
|
2.0
|
80,000
|
|
$0.57
|
400,000
|
3.1
|
160,000
|
|
$1.44
|
100,000
|
3.4
|
100,000
|
|
$0.70
|
100,000
|
4.0
|
100,000
|
|
$0.50
|
400,000
|
5.7
|
-
|
|
3,021,000
|
2,381,000
|
During
2009, the Company issued options to purchase 25,000 shares at $0.70 per share to
each of the non-executive directors. These options vested upon grant date
(January 8, 2009) and expire January 7, 2014. In addition, the
Company issued options to purchase 400,000 shares at $0.50 per share to Michael
J. Rugen, Chief Financial Officer. The options were issued on
September 28, 2009. The options will vest over a five year period and
will expire on September 27, 2015. Also during 2009, Mark A. Ruth,
former Chief Financial Officer, exercised 400,000 options at $0.27 per
share.
The
weighted average fair value per share of options granted in 2008 and 2009 range
from $0.39 to $1.06, calculated using the Black Scholes option pricing
model.
Compensation
expense related to stock options was $0.2 million in 2009 and 2008 and $0.1
million in 2007. At December 31, 2009, there was $0.2 million of
total unrecognized compensation costs related to unvested options that is
expected to be recognized over a weighted average period of approximately 2.1
years.
The fair
value of stock options used to compute share based compensation is the estimated
present value at grant date using the Black Scholes option pricing model with
the following weighted average assumptions for 2008 and 2009: expected
volatility of 100%, a risk free interest rate of 3.67% and an expected option
life remaining from 0.3 to 5.7 years.
On
February 8, 2010, the Company issued options to purchase 25,000 common shares at
$0.43 per share to each of the non-executive directors. These options
vested upon grant date and will expire February 7, 2015.
F-28
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
16.
Income Taxes
The
Company had no taxable income for the year ended December 31, 2009, but had
taxable income for the years ended December 31, 2008 and 2007.
A
reconciliation of the statutory U.S. Federal income tax and the income tax
provision included in the accompanying consolidated statements of operations is
as follows: (in thousands)
|
December 31,
|
|||
|
2009
|
2008
|
2007
|
|
|
Statutory
rate
|
34%
|
34%
|
34%
|
|
Tax
(benefit)/ expense at statutory rate
|
$(744)
|
$(2,323)
|
$
480
|
|
State
income tax expense
|
142
|
197
|
140
|
|
Impairment
write-down not deductible for tax purposes
|
-
|
3,947
|
-
|
|
Unrealized
loss on derivatives not deductible for tax purposes
|
446
|
-
|
-
|
|
Excess
tax depreciation
|
(75)
|
(65)
|
(85)
|
|
Other
|
62
|
(132)
|
3
|
|
Utilization
of NOL carry-forward
|
-
|
(1,624)
|
(538)
|
|
Net
Change in deferred tax asset valuation allowance
|
(169)
|
(7,001)
|
(2,100)
|
|
Total
income tax provision (benefit)
|
$(169)
|
$(7,001)
|
$(2,100)
|
Management
has evaluated the positions taken in connection with the tax provisions and tax
compliance for the years included in these financial statements as required by
ASC 740. The Company does not believe that any of its positions it
has taken will not prevail on a more likely than not basis. As such
no disclosure of such positions was deemed necessary. Management
continuously estimates its ability to recognize a deferred tax asset related to
prior period net operating loss carry forwards based on its anticipation of the
likely timing and adequacy of future net income. The Company has had
recurring taxable income for its last three fiscal years. As of
January 1, 2009, the Company had available approximately $15.5 million of net
operating loss carry forwards to offset future taxable income.
During
the year ended December 31, 2009, Management, using the “more likely than not”
criteria for recognition, elected to recognize a deferred tax asset of $0.2
million. The recognition of the deferred tax asset in 2009 relates to
net operating loss carryforwards and will provide a better matching of income
tax expense with taxable income in future periods. The current
provision reflects the recognition of $0.2 million current income tax benefit
(fully offset by the current provision related to 2009 taxable income) and $9.1
million.
At December 31, 2009, the deferred tax
asset balance is $9.3 million. At December 31, 2008, the deferred tax
asset balance was $9.1 million. The Company recorded an additional
$3.9 million deferred tax benefit as a result of the $11.6 million ceiling test
write-down. The recognition of the deferred tax asset will provide a
better matching of income tax expense with taxable income in future
periods.
F-29
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
As of
December 31, 2009, the Company had net operating loss carry forwards of
approximately $15.5 million which will expire between 2011 and 2023 if not
utilized. Our open tax years include all returns filed for 2006 and
later.
The
Company’s deferred tax assets and liabilities are as follows:
(in
thousands)
|
Year Ended December 31
,
|
|||
|
2009
|
2008
|
2007
|
|
|
Deferred tax
assets
:
|
|||
|
Net
operating loss carry-forward
|
$ 5,982
|
$ 6,015
|
$ 7,314
|
|
Capital
loss carry-forward
|
263
|
263
|
263
|
|
Excess
of tax over book basis of oil and gas properties
|
4,334
|
3,947
|
-
|
|
Total
deferred tax assets
|
$10,579
|
$10,225
|
$ 7,577
|
|
Deferred
tax liability
|
|||
|
Basis
difference in pipeline
|
$ 1,309
|
$ 1,124
|
$ 1,209
|
|
Total
deferred liability
|
1,309
|
1,124
|
1,209
|
|
Total
net deferred taxes
|
$ 9,270
|
$ 9,101
|
$ 6,368
|
|
Valuation
allowance
|
-
|
-
|
(4,268)
|
|
Net
deferred tax asset
|
$ 9,270
|
$ 9,101
|
$ 2,100
|
17.
Supplemental Cash Flow Information
The
Company paid approximately $0.6 million, $0.4 million, and $0.3 million, for
interest in 2009, 2008, and 2007 respectively. No interest was
capitalized in 2009, 2008, or 2007.
18.
Litigation Settlement
On May
10, 2004 the Court entered its final order approving the fairness of the
settlement to the class, dismissing the action pursuant to a Settlement
Stipulation, and fully releasing the claims of the class members
in
Paul
Miller v. M. E. Ratliff and Tengasco, Inc
.
No. 3:02-CV-644
in the Unites States District Court for the Eastern District of Tennessee,
Knoxville, Tennessee. This action sought certification of a class
action to recover on behalf of a class of all persons who purchased shares of
the Company’s common stock between August 1, 2001 and April 23, 2002,
unspecified damages allegedly caused by violations of the federal securities
laws. In January, 2004 all parties reached a settlement subject to
court approval. The Court entered its order approving the settlement
on May 10, 2004. Under the settlement, the Company paid into a settlement fund
the amount of $37,500 to include all costs of administration and contribute
150,000 warrants to purchase a share of the Company’s common stock for a period
of three years from date of issue at $1 per share subject to
adjustments. The Rights Offering adjusted this price to $0.45 per
share. These warrants expired on September 12, 2008.
F-30
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
19.
Bank Debt
On
December 17, 2007, Citibank assigned the Company’s revolving credit facility
with Citibank to Sovereign Bank of Dallas, Texas (“Sovereign”) as requested by
the Company. Under the facility as assigned to Sovereign, loans and letters of
credit are available to the Company on a revolving basis in an amount
outstanding not to exceed the lesser of $20 million or the Company’s borrowing
base in effect from time to time. The Sovereign facility is secured by
substantially all of the Company’s producing and non-producing oil and gas
properties and pipeline and the Company’s Methane Project assets. The Company’s
initial borrowing base with Sovereign was set at $7.0 million, an increase from
its borrowing base of $3.3 million with Citibank prior to the
assignment.
On June
2, 2008, the Company entered into an amendment to its credit facility with
Sovereign whereby the Company’s borrowing base was raised by Sovereign as a
result of its review of the Company’s currently owned producing
properties. The borrowing base was raised to $11 million effective June 2,
2008. The amendment also set the interest rate to the greater of prime
plus 0.25% or 6% per annum. The Company had previously utilized about
$4.2 million of the facility, leaving approximately $6.8 million then available
for use by the Company upon this borrowing base increase. The Company used
$5.35 million of the then available $6.8 million for the purchase of the Riffe
Field properties in Kansas.
On
February 5, 2009, the Company amended its credit facility with Sovereign to
provide for a monthly reduction of the Bank’s commitment by $0.15 million per
month for the five month period of February through June 2009. This
commitment reduction is not a cash payment obligation of the Company but has the
effect of reducing the Company’s available borrowing base in monthly increments
of $0.15 million so that by June 2009 the Company’s available borrowing base
under the Sovereign facility was to be reduced by $0.75 million from $11.0
million to $10.25 million.
On July
9, 2009, the Company’s borrowing base was increased from $10.25 million to $11.0
million under the revolving senior credit facility between the Company and
Sovereign. The Company’s borrowing base was increased on the completion of the
regular semiannual borrowing base review by Sovereign. The $11.0
million borrowing base is again made subject to a monthly available-credit
reduction of $0.15 million per month beginning August 5, 2009, so that by the
time of the next regular borrowing base review in six months, the borrowing base
will again be $10.25 million.
As of
September 30, 2009, the Company was out of compliance on the Leverage Ratio and
Interest Coverage Ratio covenants under the credit facility. The Company was in
compliance with the remaining financial covenants under the credit
facility. The noncompliance occurred primarily as a result of the low
commodity prices in the last quarter of 2008 and first and second quarters of
2009 that are included in the covenant compliance calculations. The
Company has received a waiver from Sovereign Bank for noncompliance of these
covenants for the quarter ended September 30, 2009. There can be no
assurances that Sovereign Bank will waive noncompliance of covenants should
future instances occur.
F-31
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
On
February 23, 2010, the Company entered into an amendment to its credit facility
with Sovereign. This amendment increased the borrowing base from $10.25 million
to $11.0 million as a result of the completion of the semiannual borrowing base
review by Sovereign. The amendment also reduced the monthly
commitment reduction from $0.15 million to $0.1 million. The
amendment also changed the maturity date to June 30, 2011. In
addition, the amendment modified the covenant compliance
calculations. This modification allowed the Company to exclude the
first and second quarters of 2009. As of December 31, 2009, the
Company was in compliance with all covenants. The next borrowing base review
will take place in June 2010.
The total
borrowing by the Company under the facility at December 31, 2008 and 2009 was
$9.9 million.
20. Methane
Project
On
October 24, 2006, the Company signed a twenty-year Landfill Gas Sale and
Purchase Agreement (the “Agreement”) with BFI Waste Systems of Tennessee, LLC
(“BFI”), an affiliate of Allied Waste Industries (“Allied”). In 2008, Allied
merged into Republic Services, Inc. (“Republic”). The Company assigned its
interest in the Agreement to MMC and provides that MMC will purchase the entire
naturally produced gas stream being collected at the Carter Valley municipal
solid waste landfill owned and operated by Republic in Church Hill, Tennessee
serving the metropolitan area of Kingsport, Tennessee. Republic’s
facility is located about two miles from the Company’s pipeline. The
Company installed a proprietary combination of advanced gas treatment technology
to extract the methane component of the purchased gas stream. Methane is
the principal component of natural gas and makes up about half of the purchased
raw gas stream by volume. The Company has constructed a pipeline to
deliver the extracted methane gas to the Company’s existing pipeline (the
“Methane Project”).
The total
cost for the Methane Project, including pipeline construction, was approximately
$4.5 million. The costs of the Methane Project were funded primarily by (a) the
money received by the Company from Hoactzin to purchase its interest in the Ten
Well Program which exceeded the Company’s actual costs of drilling the wells in
that Program by more than $1 million; (b) cash flow from the Company’s
operations; and (c) $0.8 million of the funds the Company borrowed under its
credit facility with Sovereign Bank of Dallas, Texas (“Sovereign Bank”). Methane
gas produced by the project facilities was initially mixed in the Company’s
pipeline and delivered and sold to Eastman under the terms of the Company’s
natural gas purchase and sale agreement with Eastman. At current gas production
rates in the landfill itself and expected extraction efficiencies, the Company
estimates it will be able to produce and deliver about 400 Mcfd of methane sales
gas. The gas supply from this landfill is projected to grow over the
years as the underlying operating landfill continues to expand and generate
additional naturally produced gas, and for several years following the closing
of the landfill, estimated by Republic to occur between the years 2022 and
2029. Gas production will continue in commercial quantities up to 15
years after closure of the landfill.
F-32
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
As part
of the Methane Project agreement, the Company agreed to install a new force-main
water drainage line for Republic, the landfill owner, in the same two-mile
pipeline trench as the gas pipeline needed for the Project, reducing overall
costs and avoiding environmental effects to private landowners resulting from
multiple installations of pipeline. Republic paid the additional
material costs for including the water line of approximately $0.7
million. As a certificated utility, the Company’s pipeline
subsidiary, TPC, required no additional permits for the gas pipeline
construction. Initial test volumes of methane were produced in late December
2008. During the first two months of 2009, Eastman was reviewing its
current air quality permits with regard to MMC’s methane production and
deliveries did not occur during that review.
MMC
declared startup of commercial operations on April 1,
2009. During the month of April, the facility produced and sold
14 MMcf of methane gas to Eastman and was online about 91% of the calendar
month. System maintenance and landfill supply adjustments accounted for the
remainder of the time. On May 1, 2009, Eastman advised MMC that it
was suspending deliveries of the methane gas stream pending approval by the
federal Environmental Protection Agency (“EPA”) of Eastman’s petition for
inclusion of treated methane gas as natural gas within the meaning of the EPA’s
continuous emission monitoring rules applicable to Eastman’s large boilers
during the annual “smog season” beginning May 1 of each
year. Although Eastman had begun seeking this approval in February,
2009, with the assistance of the Air Quality Department of the Tennessee
Department of Environment and Conservation, the EPA had not acted by May
1. Eastman furnished to the EPA information provided by MMC that
establishes that the methane gas stream is better fuel under the rule standards
than even “natural” gas, which is technically defined in the smog season rules
to include gas being “found in geologic formations beneath the earth’s
surface”. Methane sales to Eastman were intended to resume upon EPA’s
formal approval of Eastman’s petition or expansion of the regulatory definition,
or both. However, as of December 31, 2009 neither of these actions
has been taken by EPA, despite the existence of EPA’s own established agency
initiative, the Landfill Methane Outreach Program, which is intended to
encourage beneficial use of the methane component of raw landfill
gas. Because approval was not received, MMC was forced to seek
alternative markets for the methane gas stream.
Effective
September 1, 2009 the Company began sales of its Swan Creek gas production to
Hawkins County Gas Utility District, because the physical mixing of Swan Creek
natural gas with MMC’s methane gas caused Eastman to suspend deliveries of both
categories of gas as mixed.
The
Company concluded an agreement for sale of the methane gas to Hawkins County Gas
Utility, a local utility commencing August 1, 2009 on a month to month basis
until either sales to Eastman may resume or other customers were located by the
Company.
On August
27, 2009, the Company entered into a five-year fixed price gas sales contract
with Atmos Energy Marketing, LLC, (“AEM”) in Houston, Texas, a nonregulated unit
of Atmos Energy Corporation (NYSE: ATO) for the sale of the methane component of
landfill gas produced by MMC at the Carter Valley Landfill. The
agreement provides for the sale of up to 600 MMBtu per day. The
contract is effective beginning with September 2009 gas production and ends July
31, 2014.
F-33
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
The
agreed contract price of over $6 per MMBtu was a premium to the then current
five-year strip price for natural gas on the NYMEX futures market. MMC’s
plant is capable of producing a daily average of about 400 Mcfd of methane from
the Carter Valley landfill at current raw gas volumes. However, daily
production during September and October 2009 at MMC’s facility was intermittent
due to a combination of temporary factors. Average daily production
for September and October 2009 was 248 Mcfd on the twenty days the plant was in
production. In November 2009, MMC’s average daily gas production on
producing days was 288 Mcfd of sales methane and in December 2009, this amount
was 293 Mcfd of sales methane.
On September 17, 2007, Hoactzin,
simultaneously with subscribing to participate in the Ten Well Program (the
“Program”), pursuant to a separate agreement with the Company was conveyed a 75%
net profits interest in the Methane Project. The revenues from the Methane
Project received by Hoactzin are to be applied towards the determination of the
Payout Point (as defined above) for the Ten Well Program. When the
Payout Point is reached from either the revenues from the wells drilled in the
Program or the Methane Project or a combination thereof, Hoactzin’s net profits
interest in the Methane Project will decrease to a 7.5% net profits
interest. The Company believes that the application of revenues
from the Methane Project to reach the Payout Point could accelerate reaching the
Payout Point. As stated above, the Purchase Price paid by Hoactzin
for its interest in the Program exceeded the Company’s anticipated and actual
costs of drilling the ten wells in the Program. Those excess funds provided by
Hoactzin were used to pay for approximately $1 million of equipment required for
the Methane Project, or about 22% of the Project’s capital costs. The
availability of the funds provided by Hoactzin eliminated the need for the
Company to borrow those funds, to have to pay interest to any lending
institution making such loans or to dedicate Company revenues or revenues from
the Methane Project to pay such debt service. Accordingly, the grant
of a 7.5% interest in the Methane Project to Hoactzin was negotiated by the
Company as a favorable element to the Company of the overall
transaction.
21.
Restricted Cash
As
security required by Tennessee oil and gas regulations, the Company placed
$120,500 in a Certificate of Deposit to cover future asset retirement
obligations for the Company’s Tennessee wells.
F-34
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
22. Quarterly
Data and Share Information (unaudited)
The
following tables sets forth for the fiscal periods indicated, selected
consolidated financial data
(In thousands, except per share
data)
|
Fiscal
Year Ended 2009
|
1st Qtr
|
2nd Qtr
|
3rd Qtr
|
4th Qtr
|
|
Revenues
|
$ 1,900
|
$ 2,355
|
$ 2,585
|
$ 2,891
|
|
Net
loss
|
(402)
|
(81)
|
(449)
|
(1,086)
|
|
Net
loss attributable to common shareholders
|
(402)
|
(81)
|
(449)
|
(1,086)
|
|
Loss
per common share
|
$ (0.01)
|
$ (0.00)
|
$ (0.01)
|
$ (0.02)
|
|
Fiscal
Year Ended 2008
|
1st Qtr
|
2nd Qtr
|
3rd Qtr
|
4th Qtr
|
|
Revenues
|
$ 3,306
|
$ 4,634
|
$ 5,067
|
$ 2,594
|
|
Net
income (loss)
|
5,812
|
1,422
|
1,563
|
(8,627)
|
|
Net
income (loss) attributable to common shareholders
|
5,812
|
1,422
|
1,563
|
(8,627)
|
|
Income
(loss) per common share
|
$ 0.10
|
$ 0.02
|
$ 0.03
|
$ (0.14)
|
During
the first quarter of 2008, the Company recorded a $5.2 million deferred tax
asset. During the fourth quarter of 2008 the Company recorded a $11.6 million
ceiling test write-down.
23. Supplemental
Oil and Gas Information (unaudited)
Information
with respect to the Company’s oil and gas producing activities is presented in
the following tables. Estimates of reserves quantities, as well as future
production and discounted cash flows before income taxes, were determined by
LaRoche Petroleum Consultants Ltd. All of the Company’s reserves were
located in the United States.
Capitalized
Costs Related to Oil and Gas Producing Activities
The table
below reflects our capitalized costs related to our oil and gas producing
activities at December 31, 2009 and 2008 (in thousands):
|
Years Ended December 31,
|
||
|
2009
|
2008
|
|
|
Proved
oil and gas properties
|
$ 24,182
|
$ 23,031
|
|
Unproved
properties
|
109
|
1,243
|
|
Total
proved and unproved oil and gas properties
|
$ 24,291
|
$
24,274
|
|
Less
accumulate depreciation, depletion and amortization
|
11,931
|
10,132
|
|
Net
oil and gas properties
|
$ 12,360
|
$ 14,142
|
F-35
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
Oil
and Gas Related Costs
The
following table sets forth information concerning costs incurred related to the
Company’s oil and gas property acquisition, exploration and development
activities (in thousands):
|
Years Ended December 31,
|
|||
|
2009
|
2008
|
2007
|
|
|
Property
acquisitions proved
|
$
-
|
$ 5,350
|
$ 200
|
|
Property
acquisitions unproved
|
-
|
-
|
-
|
|
Exploration
cost
|
-
|
-
|
-
|
|
Development
cost
|
1,020
|
6,614
|
4,991
|
|
Total
|
$ 1,020
|
$ 11,964
|
$ 5,191
|
Results
of Operations from Oil and Gas Producing Activities
The
following table sets forth the Company’s results of operations from oil and gas
producing activities. (in thousands)
|
Year Ended December 31
,
|
|||||
|
2009
|
2008
|
2007
|
|||
|
Revenues
|
$ 9,711
|
$15,570
|
$ 9,300
|
||
|
Production
costs and taxes
|
(5,225)
|
(5,731)
|
(4,160)
|
||
|
Depreciation,
depletion and amortization
|
(1,800)
|
(1,374)
|
(835)
|
||
|
Income
from oil and gas producing activities
|
$ 2,686
|
$ 8,465
|
$ 4,305
|
||
In the
presentation above, no deduction has been made for indirect costs such as
corporate overhead or interest expense. No income taxes are reflected above due
to the Company’s operating tax loss carry-forwards.
F-36
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
Estimated
Quantities of Oil and Gas Reserves
The
following table sets forth the Company’s net proved oil and gas reserves and the
changes in net proved oil and gas reserves for the years ended December 31,
2009, 2008 and 2007.
|
Oil
(MBbls)
|
Gas
(MMcf)
|
MBOE
|
|
|
Proved
reserves at December 31, 2006
|
1,712
|
1,307
|
1,930
|
|
Revisions
of previous estimates
|
700
|
(46)
|
692
|
|
Improved
recovery
|
19
|
-
|
19
|
|
Purchase
of reserves in place
|
16
|
-
|
16
|
|
Extensions
and discoveries
|
14
|
-
|
14
|
|
Production
|
(185)
|
(127)
|
(206)
|
|
Sales
of reserves in place
|
-
|
-
|
-
|
|
Proved
reserves at December 31, 2007
|
2,276
|
1,134
|
2,465
|
|
Revisions
of previous estimates
|
(1,313)
|
(120)
|
(1,333)
|
|
Improved
recovery
|
59
|
-
|
59
|
|
Purchase
of reserves in place
|
234
|
-
|
234
|
|
Extensions
and discoveries
|
154
|
-
|
154
|
|
Production
|
(162)
|
(104)
|
(180)
|
|
Sales
of reserves in place
|
-
|
-
|
|
|
Proved
reserves at December 31, 2008
|
1,248
|
910
|
1,399
|
|
Revisions
of previous estimates
|
1,203
|
(721)
|
1,084
|
|
Improved
recovery
|
-
|
-
|
-
|
|
Purchase
of reserves in place
|
-
|
-
|
-
|
|
Extensions
and discoveries
|
-
|
-
|
-
|
|
Production
|
(171)
|
(73)
|
(183)
|
|
Sales
of reserves in place
|
(7)
|
--
|
(7)
|
|
Proved
reserves at December 31, 2009
|
2,273
|
116
|
2,293
|
|
Proved
developed reserves at:
|
|||
|
December
31, 2007
|
1,605
|
1,131
|
1,793
|
|
December
31, 2008
|
1,240
|
907
|
1,391
|
|
December
31, 2009
|
1,579
|
116
|
1,598
|
F-37
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
|
(amounts
in thousands)
|
Year Ended 12/31/09
|
Year Ended 12/31/08
|
Year Ended 12/31/07
|
||||||||
|
Oil
|
Gas
|
Total
|
Oil
|
Gas
|
Total
|
Oil
|
Gas
|
Total
|
|||
|
Total
proved reserves year-end reserve report
|
$27,964
|
223
|
$28,187
|
$9,177
|
1,116
|
$10,293
|
$52,117
|
1,510
|
$53,627
|
||
|
Proved
developed producing reserves (PDP)
|
$15,476
|
223
|
$15,699
|
$9,020
|
1,114
|
$10,134
|
$36,319
|
1,485
|
$37,804
|
||
|
%
of PDP reserves to total proved reserves
|
55%
|
1%
|
56%
|
87%
|
11%
|
98%
|
67%
|
3%
|
70%
|
||
|
Proved
developed non-producing reserves
|
$5,185
|
-
|
$5,185
|
$157
|
2
|
$159
|
$441
|
25
|
$466
|
||
|
%
of PDNP reserves to total proved reserves
|
18%
|
-
|
18%
|
2%
|
-
|
2%
|
1%
|
-
|
1%
|
||
|
Proved
undeveloped reserves (PUD)
|
$7,303
|
-
|
$7,303
|
-
|
-
|
-
|
$15,357
|
-
|
$15,357
|
||
|
%
of PUD reserves to total proved reserves
|
26%
|
-
|
26%
|
-
|
-
|
-
|
29%
|
-
|
29%
|
||
S
tandardized Measure of Discounted
Future Net Cash Flows
The standardized measure of discounted
future net cash flows from the Company’s proved oil and gas reserves is
presented in the following table: (in thousands
):
|
December
31,
|
||||||
|
2009
|
2008
|
2007
|
||||
|
Future
cash inflows
|
$ 122,844
|
$
51,388
|
$ 206,276
|
|||
|
Future
production costs and taxes
|
(56,550)
|
(36,491)
|
(76,944)
|
|||
|
Future
development costs
|
(11,039)
|
(309)
|
(10,175)
|
|||
|
Future
income tax expenses
|
-
|
-
|
-
|
|||
|
Net
future cash flows
|
55,255
|
14,588
|
119,157
|
|||
|
Discount
at 10% for timing of cash flows
|
(27,068)
|
(4,295)
|
(65,530)
|
|||
|
Discounted
future net cash flows from proved reserves
|
$ 28,187
|
$ 10,293
|
$ 53,627
|
|||
F-38
Tengasco,
Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
The
following are the principal sources of change in the standardized measure of
discounted future net cash flows from the Company’s proved oil and gas reserves
(in thousands):
|
December
31,
|
|||||
|
2009
|
2008
|
2007
|
|||
|
Balance,
beginning of year
|
$10,293
|
$53,627
|
$26,469
|
||
|
Sales,
net of production costs and taxes
|
(4,486)
|
(9,839)
|
(5,140)
|
||
|
Discoveries
and extensions, net of costs
|
-
|
1,492
|
1,166
|
||
|
Purchase
of reserves in place
|
-
|
1,642
|
568
|
||
|
Sale
of reserves in place
|
(109)
|
-
|
-
|
||
|
Net
changes in prices and production costs
|
10,433
|
(30,890)
|
16,893
|
||
|
Revisions
of quantity estimates
|
17,705
|
(9,373)
|
16,584
|
||
|
Accretion
of discount
|
1,029
|
1,029
|
2,647
|
||
|
Net
change in income taxes
|
-
|
-
|
-
|
||
|
Previously
estimated development cost incurred during the year
|
28
|
-
|
-
|
||
|
Changes
in future development costs
|
(5,489)
|
3,251
|
(5,669)
|
||
|
Changes
in production rates and other
|
(1,217)
|
(646)
|
109
|
||
|
Balance,
end of year
|
$28,187
|
$10,293
|
$53,627
|
||
Estimated future net cash flows
represent an estimate of future net revenues from the production of proved
reserves using current sales prices, along with estimates of the operating
costs, production taxes and future development and abandonment cost (less
salvage value) necessary to produce such reserves. The prices used for December
31, 2009, 2008 and 2007 were $53.81, $33.96, and $85.44, per barrel of oil and
$4.61, $7.76, and $7.21 per MCF of gas, respectively. The Company’s proved
reserves as of December 31, 2009 were measured by using commodity prices based
on the twelve month unweighted arithmetic average of the first day of the month
price for the period January through December 2009. The Company’s
proved reserves as of December 31, 2008 and 2007 were measured by using end of
year prices. No deduction has been made for depreciation, depletion or any
indirect costs such as general corporate overhead or interest
expense.
F-39
TABLE OF CONTENTS
Part IItem 1. BusinessItem 1A. Risk FactorsItem 1B. Unresolved Staff CommentsItem 2. PropertiesItem 3. Legal ProceedingsItem 4. (removed and Reserved)Part IIItem 5. Market For Registrant S Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity SecuritiesItem 6. Selected Financial DataItem 7. Management S Discussion and Analysis Of Financial Condition and Results Of OperationsItem 7A. Quantitative and Qualitative Disclosure About Market RisksItem 8. Financial Statements and Supplementary DataItem 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureItem 9a(t). Controls and ProceduresItem 9B. Other InformationPart IIIItem 10. Directors, Executive Officers and Corporate GoveranceItem 11. Executive CompensationItem 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholders MattersItem 13. Certain Relationships and Related Transactions, and Director IndependenceItem 14. Principal Accounting Fees and ServicesPart IVItem 15. Exhibits and Financial Statements Schedules