# UNITED STATESSECURITIES AND
EXCHANGE COMMISSIONWASHINGTON, D.C. 20549

# REPORT ON FORM 10-K/A

(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, 2004 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.0-20975

TENGASCO, INC.

(Name of registrant
as specified in its charter)

|Tennessee                                                      |  | 87-0267438                         
|-------------------------------------------------------------- |  | -----------------------------------
|(State or other jurisdiction of incorporation or organization) |  | (I.R.S. EmployerIdentification No.)

10215 Technology Drive Suite 301, Knoxville, Tennessee 3732(Address
of Principal Executive Offices) (Zip Code)



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 checkmark 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 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 if disclosure of delinquent filers in response to Item 405 of Regulation SK
is not contained in this form and no disclosure will be contained, to the best of the
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 checkmark  whether the  registrant  is an  accelerated  filer (as defined in Rule 12b-2 of the
Act): Yes / / No /X/

Indicate by checkmark whether the
registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act): Yes // No /X/

State
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 quarter (June 30, 2004 closing
price $0.38): $11,854,484

State
the number of shares outstanding of the registrants $.001 par value common stock as
of the close of business on the latest practicable date (February 1, 2005): 48,927,828

This
Amendment on Form No. 1 to Form 10-K amends our annual report for the year ended December
31, 2004 filed on March 31, 2005. There are four amendments to the Form 10-K. First, page 4 of the Form 10-K is amended to
further clarify the relationship between actual production levels and proved reserves
calculations in 2003 and 2004.  Second, page F-6 is amended to reposition the Net Loss to be located before deducting dividends on preferred stock
necessary to arrive at net loss attributable to common stockholders. 
This affects only the year 2003, and has no effect on any calculation of net loss to
common shareholders in any year. The third amendment is made on page F-12 to include an affirmative statement that the Company has no undeveloped unproved propterties so
none were excluded from the full cost pool. The fourth amendment which is at page F-15 is to include additional information concerning the
percentage of revenues supplied by customers contributing more than ten percent of
revenues.

Documents
Incorporated By Reference: None.

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2002 through 2004 due to ongoing disputes with Bank One, the Companys
principal lender, and the resulting lack of available capital. That dispute was finally
settled in May 2004.

After
the Bank One lawsuit was resolved, the Company drilled two new wells in 2004 in the Swan
Creek Field to the Knox Formation. This resulted in one producing well, the Steve Lawson
#8, which is currently producing approximately 10,000 cubic feet of natural gas per day.
The other well, the Hazel Sutton #3, did not result in the production of commercial
volumes of gas. An attempt was made to have this well produce oil from the Trenton
formation, a shallower interval, but this also proved unsuccessful. The Company does not
believe it is likely that commercial quantities of oil or gas will occur from the Hazel
Sutton #3 well and it is anticipated that upon final review it will be plugged.

Because
the Knox formation of the Swan Creek Field has been now been more specifically defined by
the accumulation of data from previously drilled wells and seismic data, the Company now
believes that drilling new gas wells in the Field 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.

Further,
the Company now expects that even if new wells were drilled in the Swan Creek Field, the
deliverability of natural gas from the Field will not be sufficient to satisfy the volumes
deliverable under its contracts with Eastman and BAE in Kingsport, Tennessee. The Eastman
contract provides that Eastman will buy a minimum of the lesser of eighty percent of that
customers daily usage or 10,000 MMBtu per day, and the BAE contract provides that
BAE will buy a minimum of all of that customers usage or 5,000 MMbtu per day after
Eastmans volumes have been provided. The Companys current production from the
Swan Creek field is approximately 745 MMBtu per day. The Companys contracts with
these customers are only for gas produced from the Swan Creek Field. So long as that Field
is not capable of supplying these volumes, the Company is not in breach or violation of
these contracts. No penalty is associated with the inability of the Field to produce the
volumes that the Company could deliver and buyers would be obligated to buy under its
industrial contracts if the volumes were physically available from the Field. However, in
the event that the Company were found to be in breach of its obligations for failure to
deliver any volumes of gas that is produced from the Swan Creek Field to either of these
customers, the agreements limit potential exposure to damages. Damages are limited to no
more than $.40 per MMBtu for any replacement volumes that are proved in a court proceeding
as having been obtained to replace volumes required to be furnished but not furnished by
the Company.

The
experienced decline in actual production levels from existing wells in the Swan Creek
Field was expected and does not diminish either the shut-in pressure or the
Companys proved producing reserves in the Swan Creek Field. The declines,
however, suggest the production rates from some of the Companys wells will
continue to be slower, which may result in such wells lasting longer than originally
expected. Although there can be no assurance, the Company expects these natural rates
of decline will be less than the decline experienced to date, and that ongoing
production from existing wells will tend to stabilize near current production
levels. The Company anticipates that the natural decline of production from
existing wells is now predictable in the Swan Creek Field, and that proven producing reserves can be extracted primarily through existing wells; however, the total volume
of proved reserves in the Swan Creek field was reduced from 16.3 BCF reported in 2003 to 6.7 BCF in 2004, a
reduction of 41%.

In
2003 management had obtained state regulatory approval for drilling of infield wells in
the Swan Creek field at increased density of wells. Management expected that an
increased density of wells within the existing Swan Creek field would result in
additional reserves and reported those reserves as proven in accordance with
reservoir engineering standards. In 2004, the Company drilled and tested two new infield developmental wells in the Swan Creek field as discussed above. Contrary to the
expectations for additional infield developmental wells, drilling and testing
results of the first two wells indicated that the current wells in production in the Swan Creek Field would
be capable of and would likely produce all the remaining reserves, in that Field and that only
limited additional gas reserves could be added with additional infield developmental drilling. Accordingly, the proven reserves associated with the increased
number of infield developmental wells in 2003 were not included in the proven
reserves reported by the Company in 2004, resulting in a volume change from 16.3
BCF in 2003 to 6.7 BCF in 2004 of total proven gas reserves in the Swan Creek Field.
See Note 18 to the Consolidated Financial Statements. This change was almost entirely related to undeveloped locations that management now believes do not have a
likelihood of being drilled in the future, and was not related in any manner to
the natural decline in production experienced in 2004 from existing wells in the
Swan Creek Field as discussed above.

4

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Natural
gas production from the Swan Creek Field during 2004 averaged 611 thousand cubic feet per
day compared to 1.053 million cubic feet per day in 2003.

During
2004, the Company had 22 producing gas wells and 5 producing oil wells in the Swan Creek
Field. Miller Petroleum, Inc. and others had a participating interest in 7 of these wells.
See, Item 2  Description of Property  Property Location, Facilities,
Size and Nature of Ownership. In total, the Company has completed 47 wells in the
Swan Creek Field. The majority of these gas wells were drilled prior to the completion of
the pipeline system so only test data was available prior to full production. Of the
completed wells, 12 are not producing commercial quantities of hydrocarbons and will not
be tied in to the Companys pipeline since the expense of connection is not justified
in view of the expected volumes to be produced.

# 2. The Kansas
Properties

In
1998, the Company acquired the Kansas Properties, which presently include 129 producing
oil wells and 51 producing gas wells in the vicinity of Hays, Kansas and a 50 mile gas
gathering system. The Company also acquired 37 other wells, which now serve as saltwater
disposal wells in the vicinity of Hays, Kansas. These saltwater disposal wells reduce
operating costs by eliminating the need for transportation out of the area of the salt
water produced in the oil production process. The aggregate production for the Kansas
Properties in 2004 was 716 Mcf of gas and 326 barrels of oil per day. Revenue for the
Kansas Properties was approximately $383,909 per month in 2004. The Company employs a full
time geologist in Kansas to oversee operations of the Kansas Properties.

In
2004, the Company drilled one new well in Kansas, the Lewis No. 3 Well. This well was
drilled to the Arbuckle formation, and is currently producing 39 barrels of oil per day.
In December 2004, the Company commenced a lease acquisition program in Kansas and as of
the date of this report, has increased its lease position from 32,158 acres to 42,895
acres by acquiring oil and gas leases in an area near its previous lease holdings where
the Company believes there is a likelihood of additional oil production. This newly
acquired acreage is largely undrilled, and the Company believes that current seismic
exploration technology will enable the Company to establish additional oil production by
efficient location of new wells to be drilled by the Company. The Company intends to
continue to acquire additional leases in the area of its existing wells.

In
February and March 2005, the Company began drilling the first two wells of an eight-well
drilling program in Kansas (the Drilling Program or the Program).
The Program was offered to the holders of the Companys Series A 8% Cumulative
Convertible Preferred

5

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Tengasco, Inc. and SubsidiariesConsolidated
Statements of Loss



|Years ended December 31,                                                                                             | 2004 | 2003 | 2002
|-------------------------------------------------------------------------------------------------------------------- | ---- | ---- | ----
|Revenues and other income                                                                                            |      |      |     
|Oil and gas revenues                                                                                                 |      |      | $   
|Pipeline transportation revenues                                                                                     |      |      |     
|Interest Income                                                                                                      |      |      |     
|                                                                                                                    
|Total revenues and other income                                                                                      |      |      |     
|                                                                                                                    
|Costs and expenses                                                                                                   |      |     
|Production costs and taxes                                                                                           |      |      |     
|Depreciation, depletion and amortization                                                                             |      |     
|(Notes 4, 5 and 6)                                                                                                   |      |      |     
|General and administrative                                                                                           |      |      |     
|Interest expense (Notes 9, 10 and 13)                                                                                |      |      |     
|Public relations                                                                                                     |      |      |     
|Professional fees                                                                                                    |      |      |     
|Loss on impairment of long-lived asset                                                                               |      |      |     
|Loss on sale of equipment, net                                                                                       |      |      |     
|                                                                                                                    
|Total costs and expenses                                                                                             |      |      |     
|                                                                                                                    
|Operating loss                                                                                                       |      |      |     
|Gain from extinguishment of debt (Note 16)                                                                           |      |      |     
|Gain on Preferred Stock (Note 9)                                                                                     |      |      |     
|                                                                                                                    
|Net loss  before                                                                                                     |      |     
|Cumulative effects of a changes in accounting principle                                                              |      |      |     
|Cumulative effect of a change in accounting principle (Note 10)                                                      |      |      |     
|Cumulative effect of a change in accounting principle (Note 9)                                                       |      |      |     
|                                                                                                                    
|Net loss                                                                                                             |      |      |     
|Dividends on preferred stock (Note 9)                                                                                |      |      |     
|                                                                                                                    
|Net loss attributable to common stockholders                                                                         |      |      | $   
|                                                                                                                    
|Net loss attributable to common stockholders per shares                                                              |      |      |     
|Basic and diluted:                                                                                                   |      |      |     
|Net loss attributable to common stockholders before cumulative          effects of a changes in accounting principle |      |      | $   
|Cumulative effect of a change in accounting principle (Note 10)                                                      |      |      |     
|Cumulative effect of a change in accounting principle (Note 9)                                                       |      |      |     
|                                                                                                                    
|Total                                                                                                                |      |      | $   
|                                                                                                                    
|Weighted average shares outstanding                                                                                  |      |      |     
|                                                                                                                    

F-6

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# Cash and Cash
Equivalents

| | The
Company considers all investments with a maturity of three months or less when purchased
to be cash equivalents.
| | --------------------------------------------------------------------------------------------------------------------

# Investment Securities

| | Investment
securities available for sale are reported at fair value, with unrealized gains and losses
reported as a separate component of stockholders equity, net of the related tax
effects. The Companys available for sale securities were transferred as part of a
lawsuit settlement in 2004. The Company recognized a realized loss of $150,000 as a result
of the transfer. See Note 15.
| | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

# Inventory

| | Inventory
consists primarily of crude oil in tanks and is carried at 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 productive and
nonproductive 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, delay rentals and the
costs of drilling, completing equipping and closing oil and gas wells. 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 costs of oil and gas properties, plus estimated future development 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 has no undeveloped unproved properties and consequently no such properties have been excluded from the full cost pool. These reserves were estimated by Ryder Scott Company, Petroleum Consultants in
2004, 2003 and 2002.
| | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | The
capitalized oil and gas properties, 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
| | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

F-12

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# 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.
| | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

# Concentration of
Credit Risk

| | Financial
instruments which potentially subject the Company to concentrations of credit risk consist
principally of cash and accounts receivable. At times, such cash in banks is in excess of
the FDIC insurance limit.
| | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | The
Companys primary business activities include oil and gas sales to several customers
in the states of Tennessee and Kansas. The related trade receivables subject the Company
to a concentration of credit risk within the oil and gas industry. The Company is
presently dependent upon a small number of customers for the sale of gas from the Swan
Creek Field, principally Eastman and BAE, and other industrial customers in the Kingsport
area with which the Company may enter into gas sales contracts.
| | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | The
Company has entered into contracts to supply two manufacturers with natural gas from the
Swan Creek Field (Tennessee) through the Companys pipeline. These customers are the
Companys primary customers of natural gas sales. Additionally, the Company sells a
majority of its crude oil primarily to two customers, one each in Tennessee and Kansas.
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 could
have a significant adverse effect on the Companys projected results of operations.
| | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | In
2002, the Company received 46.8 percent of its revenues from Customer A; 32.3 percent of
its revenues from Customer B; and 13.9 percent of its revenues from Customer C.
| | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | In
2003, the Company received 45.9 percent of its revenues from Customer A; 28.1 percent of
its revenues from Customer B; and 15.7 percent of its revenues from Customer C.
| | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | In
2004, the Company received 59.3 percent of its revenues from Customer A; 18.2 percent of
its revenues from Customer B; and 14.4 percent of its revenues from Customer C.
| | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | In
each of the years 2002 through 2004, the identity of the customers indicated above as
either A, B, or C was the same from year to year, although the percentage of
revenues varied slightly from year to year  for that customer.
| | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

# Loss per Common Share

| | Basic
loss per share is computed by dividing loss available to common shareholders by the
weighted average number of shares outstanding during each year. Shares issued during the
year are weighted for the portion of the year that they were outstanding. Diluted loss per
share does not differ from basic loss per share since the effect of all common stock
equivalents is anti-dilutive. Basic and diluted loss per share are based upon 40,855,972
weighted average common shares outstanding for the year ended December
| | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

F-15

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