##### Table of Contents



UNITED STATES SECURITIES AND EXCHANGE COMMISSION
 Washington, D.C. 20549
 FORM 10-K
 þ
    
    Annual Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
 For the Fiscal Year Ended December 31, 2005
 OR
 o
    
    Transition Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
 Commission File No. 0-19279
 EVERFLOW EASTERN PARTNERS, L.P.
 (Exact name of registrant as specified in its charter)
 Delaware
(State or other jurisdiction of
incorporation or organization)
    
    34-1659910
(I.R.S. Employer
Identification No.)
 585 West Main StreetP.O. Box 629Canfield, Ohio
(Address of principal executive offices)
    
    44406
(Zip Code)
 Registrants telephone number, including area code: 330-533-2692
  Name of each exchangeTitle of each class
    
    on which registered
   Units of Limited Partnership Interest
 o þ
 o þ
 þ o
 o
 o o þ
 o þ




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TABLE OF CONTENTS  PART IITEM 1. BUSINESSITEM 1A. RISK FACTORSITEM 1B. UNRESOLVED STAFF COMMENTSITEM 2. PROPERTIESITEM 3. LEGAL PROCEEDINGSITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERSPART IIITEM 5. MARKET FOR THE REGISTRANTS COMMON EQUITY AND RELATED STOCKHOLDER MATTERSITEM 6. SELECTED FINANCIAL DATAITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATAITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSUREITEM 9A. CONTROLS AND PROCEDURESITEM 9B. OTHER INFORMATIONPART IIIITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTITEM 11. EXECUTIVE COMPENSATIONITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENTITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONSITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICESPART IVITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-KSIGNATURESExhibit IndexEX-31.1 302 Certification for CEOEX-31.2 302 Certification for CFOEX-32.1 906 Certification for CEO and CFO    Table of Contents  
 PART I
 
 ITEM
1. BUSINESS
 Introduction
  Exchange Offer
   The Company
 General
  -1-




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##### Table of Contents



Registrants Common Equity and
Related Stockholder Matters
 Description of the Business
 General
 Subsidiaries
  Current Operations
  -2-
    Table of Contents    Business Plan
 Acquisition of Prospects
  Acquisition of Producing Properties
  Funding for Activities -3-
    Table of Contents       Marketing
  Oil
 -4-
    Table of Contents     Natural Gas
  -5-




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##### Table of Contents



Jan
    
    Feb
    
    Mar
    
    Apr
    
    May
    
    Jun2006
    
    2006
    
    2006
    
    2006
    
    2006
    
    2006MCF
    
    
    140,000
    
    
    
    140,000
    
    
    
    140,000
    
    
    
    90,000
    
    
    
    90,000
    
    
    
    130,000Price
    
    $
    7.65
    
    
    $
    7.65
    
    
    $
    7.65
    
    
    $
    7.45
    
    
    $
    7.45
    
    
    $
    7.21Jul
    
    Aug
    
    Sep
    
    Oct
    
    Nov
    
    Dec2006
    
    2006
    
    2006
    
    2006
    
    2006
    
    2006MCF
    
    
    90,000
    
    
    
    90,000
    
    
    
    90,000
    
    
    
    90,000
    
    
    
    140,000
    
    
    
    120,000Price
    
    $
    7.45
    
    
    $
    7.45
    
    
    $
    7.45
    
    
    $
    7.45
    
    
    $
    10.21
    
    
    $
    9.89Jan
    
    Feb
    
    Mar
    
    Apr
    
    May
    
    Jun2007
    
    2007
    
    2007
    
    2007
    
    2007
    
    2007MCF
    
    
    120,000
    
    
    
    120,000
    
    
    
    120,000
    
    
    
    80,000
    
    
    
    80,000
    
    
    
    100,000Price
    
    $
    9.89
    
    
    $
    9.89
    
    
    $
    9.89
    
    
    $
    9.78
    
    
    $
    9.78
    
    
    $
    9.81Jul
    
    Aug
    
    Sep
    
    Oct2007
    
    2007
    
    2007
    
    2007MCF
    
    
    80,000
    
    
    
    80,000
    
    
    
    80,000
    
    
    
    80,000Price
    
    $
    9.78
    
    
    $
    9.78
    
    
    $
    9.78
    
    
    $
    9.78
 -6-




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Jan
    
    Feb
    
    Mar
    
    Apr
    
    May
    
    Jun2006
    
    2006
    
    2006
    
    2006
    
    2006
    
    2006MCF
    
    
    80,000
    
    
    
    80,000
    
    
    
    80,000
    
    
    
    60,000
    
    
    
    60,000
    
    
    
    80,000Price
    
    $
    7.76
    
    
    $
    7.76
    
    
    $
    7.76
    
    
    $
    7.49
    
    
    $
    7.49
    
    
    $
    7.27Jul
    
    Aug
    
    Sep
    
    Oct
    
    Nov
    
    Dec2006
    
    2006
    
    2006
    
    2006
    
    2006
    
    2006MCF
    
    
    60,000
    
    
    
    60,000
    
    
    
    60,000
    
    
    
    60,000
    
    
    
    90,000
    
    
    
    70,000Price
    
    $
    7.49
    
    
    $
    7.49
    
    
    $
    7.49
    
    
    $
    7.49
    
    
    $
    10.75
    
    
    $
    10.40Jan
    
    Feb
    
    Mar
    
    Apr
    
    May
    
    Jun2007
    
    2007
    
    2007
    
    2007
    
    2007
    
    2007MCF
    
    
    70,000
    
    
    
    70,000
    
    
    
    70,000
    
    
    
    40,000
    
    
    
    40,000
    
    
    
    60,000Price
    
    $
    10.40
    
    
    $
    10.40
    
    
    $
    10.40
    
    
    $
    9.57
    
    
    $
    9.57
    
    
    $
    9.57Jul
    
    Aug
    
    Sep
    
    Oct2007
    
    2007
    
    2007
    
    2007MCF
    
    
    40,000
    
    
    
    40,000
    
    
    
    40,000
    
    
    
    40,000Price
    
    $
    9.57
    
    
    $
    9.57
    
    
    $
    9.57
    
    
    $
    9.57
   Seasonality
  -7-




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Title to Properties
  Competition
    -8-




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Regulation of Oil and Gas Industry
   -9-
    Table of Contents     Environmental Regulation
    Operating Hazards and Uninsured Risks
  -10-




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Conflicts of Interest
   Employees
  
 ITEM 1A. RISK FACTORS
 Natural gas and crude oil prices fluctuate widely, and low prices for an extended period of time
are likely to have a material adverse impact on our business.
 -11-
    Table of Contents     
    
    the level of consumer product demand;
    
    weather conditions;
    
    political conditions in natural gas and crude oil producing regions,
including the Middle East;
    
    the ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil price and production controls;
    
    the price of foreign imports;
    
    actions of governmental authorities;
    
    pipeline capacity constraints;
    
    inventory storage levels;
    
    domestic and foreign governmental regulations;
    
    the price, availability and acceptance of alternative fuels; and
    
    overall economic conditions.
  Drilling natural gas and crude oil wells is a high-risk activity.
  
    
    unexpected drilling conditions, pressure or irregularities in formations;
 -12-




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
    
    equipment failures or accidents;
    
    adverse weather conditions;
    
    compliance with governmental requirements; and
    
    shortages or delays in the availability of drilling rigs or crews and
the delivery of equipment.
  
    
    the availability of sufficient capital resources to us and the other
participants for the drilling of the prospects;
    
    economic and industry conditions at the time of drilling, including
prevailing and anticipated prices for natural gas and crude oil and
the availability of drilling rigs and crews;
    
    our financial resources and results; and
    
    the availability of leases and permits on reasonable terms for the prospects.
  Reserve estimates depend on many assumptions that may prove to be inaccurate. Any material
inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net
present value of our reserves to be overstated.
  -13-




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
    
    the quality and quantity of available data;
    
    the interpretation of that data;
    
    the accuracy of various mandated economic assumptions; and
    
    the judgment of the persons preparing the estimate.
   Our future performance depends on our ability to find or acquire additional natural gas and crude
oil reserves that are economically recoverable.
    -14-




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We may incur substantial impairment write-downs.
   We face a variety of hazards and risks that could cause substantial financial losses.
  
    
    blowouts, surface cratering and explosions;
    
    mechanical problems;
    
    uncontrolled flows of natural gas, crude oil or well fluids;
    
    fires;
    
    formations with abnormal pressures;
    
    pollution and other environmental risks; and
    
    natural disasters.
  -15-




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We have limited control over the activities on properties we do not operate.
  Terrorist activities and the potential for military and other actions could adversely affect our
business.
  Our ability to sell our natural gas and crude oil production could be materially harmed if we fail
to obtain adequate services such as transportation and processing.
  Competition in our industry is intense, and many of our competitors have substantially greater
financial and technological resources than we do, which could adversely affect our competitive
position.
 -16-
    Table of Contents    The loss of key personnel could adversely affect our ability to operate.
  We are subject to complex laws and regulations, including environmental regulations, which can
adversely affect the cost, manner or feasibility of doing business.
  Members of our management team own a significant number of partnership units, giving them
influence or control, and the interests of these individuals could differ from those of other
unitholders .
  -17-




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ITEM
1B. UNRESOLVED STAFF COMMENTS
  
 ITEM 2. PROPERTIES
   Proved Reserves
 Oil (BBLS)
    
    Gas (MCF)Proved Developed
    
    
    803,000
    
    
    
    51,043,000Proved Undeveloped
    
    
    
    
    
    
    Total
    
    
    803,000
    
    
    
    51,043,000
 
 (1)
    
    The Company has not determined proved reserves associated
with its proved undeveloped acreage which are not deemed
significant at December 31, 2005. A reconciliation of the
Companys proved reserves is included in the Notes to the
Financial Statements. Standardized Measure of Discounted Future Net Cash Flows
 (Thousands)Future cash inflows from sales of oil and gas
    
    $
    566,186Future production and development costs
    
    
    139,946Future asset retirement obligations, net of salvage
    
    
    9,145Future income tax expense
    
    
    8,997Future net cash flows
    
    
    408,098Effect of discounting future net cash flows
at 10% per annum
    
    
    219,835Standardized measure of discounted future
net cash flows
    
    $
    188,263
 
 (1)
    
    See the Notes to the Financial Statements for additional information. -18-




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Production
 AverageProduction
    
    Sales Price
    
    Average Lifting CostOil (BBLS)
    
    Gas (MCF)
    
    per BBL
    
    per MCF
    
    per Equivalent MCF (1)2005
    
    
    72,000
    
    
    
    3,878,000
    
    
    $
    52.40
    
    
    $
    7.42
    
    
    $
    .832004
    
    
    72,000
    
    
    
    3,932,000
    
    
    
    37.98
    
    
    
    5.68
    
    
    
    .692003
    
    
    76,000
    
    
    
    4,053,000
    
    
    
    27.93
    
    
    
    4.73
    
    
    
    .63
 
 (1)
    
    Oil production is converted to MCF equivalents at the rate of 6 MCF per BBL (barrel). Productive Wells
 Gross Wells
    
    Net WellsOil(1)
    
    Gas(1)
    
    Total
    
    Oil(1)
    
    Gas(1)
    
    Total76
    
    1,143
    
    1,219
    
    52
    
    754
    
    806
 
 (1)
    
    Oil wells are those wells which generate the majority
of their revenues from oil production; gas wells are those
wells which generate the majority of their revenues from
gas production. Acreage
 -19-




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Drilling Activity
 Development Wells (1)Productive
    
    
    DryGross
    
    
    Net
    
    
    Gross
    
    
    Net2005
    
    
    54
    
    
    
    18.16
    
    
    
    2
    
    
    
    .462004
    
    
    75
    
    
    
    33.20
    
    
    
    2
    
    
    
    .702003
    
    
    46
    
    
    
    18.87
    
    
    
    
    
    
    
    
 
 (1)
    
    All wells are located in the United States. All wells are
development wells; no exploratory wells were drilled. Present Activities
 Delivery Commitments
 Company Headquarters
 
 ITEM 3. LEGAL PROCEEDINGS
  
 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
  -20-




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PART II
 
 ITEM 5.
    
    MARKET FOR THE REGISTRANTS COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
 Market
  Distribution History
  Repurchase Right
  -21-




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ITEM 6.
    
    SELECTED FINANCIAL DATA
 Year Ended December 31,2005
    
    
    2004
    
    

2003(2)
    
    
    2002
    
    
    2001Revenue
    
    $
    33,114,351
    
    
    $
    25,670,760
    
    
    $
    21,834,446
    
    
    $
    16,757,418
    
    
    $
    16,261,220Net Income
    
    
    22,968,275
    
    
    
    16,403,297
    
    
    
    11,951,300
    
    
    
    8,004,090
    
    
    
    7,842,162Net Income Per Unit
    
    
    3.99
    
    
    
    2.84
    
    
    
    2.06
    
    
    
    1.37
    
    
    
    1.33Total Assets
    
    
    71,329,497
    
    
    
    61,481,489
    
    
    
    58,136,578
    
    
    
    52,579,304
    
    
    
    52,254,265Debt (1)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    512,014Cash Distributions Per Unit
    
    
    2.50
    
    
    
    2.25
    
    
    
    1.25
    
    
    
    1.25
    
    
    
    1.50
 
 (1)
    
    Debt includes the Companys long-term debt and borrowings under the Companys
revolving credit facility.(2)
    
    See Note 1G to the consolidated financial statements. The cumulative effect of change
in accounting principle was $471,545. 
 ITEM 7.
    
    MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 General
    Liquidity and Capital Resources
 Financial Position
  -22-




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December 31, 2005
    
    
    December 31, 2005Amount
    
    
    %
    
    
    Amount
    
    
    %(Amounts in Thousands)
    
    
    (Amounts in Thousands)Working capital
    
    $
    19,459
    
    
    
    28
    
    
    $
    12,498
    
    
    
    21
    %Property and equipment (net)
    
    
    49,503
    
    
    
    72
    
    
    
    47,600
    
    
    
    79Other
    
    
    111
    
    
    
    
    
    
    
    124
    
    
    
    Total
    
    $
    69,073
    
    
    
    100
    %
    
    $
    60,222
    
    
    
    100
    %Long-term liabilities
    
    $
    1,655
    
    
    
    2
    %
    
    $
    1,167
    
    
    
    2
    %Deferred income taxes
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Partners equity
    
    
    67,418
    
    
    
    98
    
    
    
    59,055
    
    
    
    98Total
    
    $
    69,073
    
    
    
    100
    %
    
    $
    60,222
    
    
    
    100
    %
 Cash Flows from Operating, Investing and Financing Activities
  -23-




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2005
    
    
    2004Dollars
    
    
    %
    
    
    Dollars
    
    
    %(Amounts in Thousands)Operating Activities:Net income before adjustments
    
    $
    22,968
    
    
    
    82
    %
    
    $
    16,403
    
    
    
    72
    %Adjustments
    
    
    5,075
    
    
    
    18
    
    
    
    4,748
    
    
    
    21Cash flow from operations
before working capital
changes
    
    
    28,043
    
    
    
    100
    
    
    
    21,151
    
    
    
    93Changes in working capital
    
    
    (1,614
    )
    
    
    (6
    )
    
    
    (1,492
    )
    
    
    (7
    )Net cash provided by
operating activities
    
    
    26,429
    
    
    
    94
    
    
    
    19,659
    
    
    
    86Investing Activities:Proceeds received on receivables
from employees
    
    
    41
    
    
    
    
    
    
    
    42
    
    
    
    Advances disbursed to employees
    
    
    (124
    )
    
    
    
    
    
    
    (39
    )
    
    
    Purchase of property and
equipment
    
    
    (6,401
    )
    
    
    (23
    )
    
    
    (7,964
    )
    
    
    (35
    )Proceeds on sale of property and
equipment and other assets
    
    
    11
    
    
    
    
    
    
    
    
    
    
    
    Net cash used by investing
activities
    
    
    (6,473
    )
    
    
    (23
    )
    
    
    (7,961
    )
    
    
    (27
    )Financing Activities:Distributions
    
    
    (14,371
    )
    
    
    (51
    )
    
    
    (12,979
    )
    
    
    (57
    )Repurchase and retirement
of Units
    
    
    (234
    )
    
    
    (1
    )
    
    
    (297
    )
    
    
    (1
    )Net cash used by financing
activities
    
    
    (14,605
    )
    
    
    (52
    )
    
    
    (13,276
    )
    
    
    (58
    )Net increase (decrease) in cash
and equivalents
    
    $
    5,351
    
    
    
    19
    
    
    $
    (1,578
    )
    
    
    (7
    )
 Note:
    
    All items in the previous table are calculated as a percentage of total cash sources. Total
cash sources include the following items, if positive: cash flow from operations before
working capital changes, changes in working capital, net cash provided by investing activities
and net cash provided by financing activities, plus any decrease in cash and equivalents.
  -24-




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-25-
    Table of Contents    Results of Operations
  -26-




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##### Table of Contents



Year Ended December 31,2005
    
    2004
    
    2003Revenues:Oil and gas sales
    
    
    98
    %
    
    
    98
    %
    
    
    98
    %Well management and operating
    
    
    2
    
    
    
    2
    
    
    
    2Total Revenues
    
    
    100
    
    
    
    100
    
    
    
    100Expenses:Production costs
    
    
    11
    
    
    
    12
    
    
    
    13Well management and operating
    
    
    1
    
    
    
    1
    
    
    
    1Depreciation, depletion and amortization
    
    
    15
    
    
    
    18
    
    
    
    23Accretion expense
    
    
    
    
    
    
    
    
    
    
    Abandonment and write down
of oil and gas properties
    
    
    
    
    
    
    
    
    
    
    1General and administrative
    
    
    5
    
    
    
    6
    
    
    
    6Other expense (income)
    
    
    (1
    )
    
    
    (1
    )
    
    
    (1
    )Cumulative effect of accounting change
    
    
    
    
    
    
    
    
    
    
    2Income taxes
    
    
    
    
    
    
    
    
    
    
    Total Expenses
    
    
    31
    
    
    
    36
    
    
    
    45Net income
    
    
    69
    %
    
    
    64
    %
    
    
    55
    %
    -27-




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Application of Critical Accounting Policies
 Property and Equipment
 -28-




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Asset Retirement Obligations
  -29-




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Revenue Recognition
  Inflation and Changes in Prices
  -30-
    Table of Contents     
 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
    
 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
  -31-




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EVERFLOW EASTERN PARTNERS, L. P.
 2005 CONSOLIDATED FINANCIAL REPORT
 F-1




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##### Table of Contents



PageREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
    
    F-3FINANCIAL STATEMENTSConsolidated balance sheets
    
    F-4 - F-5Consolidated statements of income
    
    F-6Consolidated statements of partners equity
    
    F-7Consolidated statements of cash flows
    
    F-8Notes to consolidated financial statements
    
    F-9 - F-24
 F-2




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Report of Independent Registered Public Accounting Firm
 
     
 F-3




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2005
    
    
    2004ASSETSCURRENT ASSETSCash and equivalents
    
    $
    13,371,923
    
    
    $
    8,020,521Accounts receivable:Production
    
    
    8,168,703
    
    
    
    5,659,921Employees
    
    
    120,801
    
    
    
    37,810Joint venture partners
    
    
    13,531
    
    
    
    Other
    
    
    40,400
    
    
    
    39,018Total current assets
    
    
    21,715,358
    
    
    
    13,757,270PROPERTY AND EQUIPMENTProved properties (successful efforts accounting method)
    
    
    136,388,136
    
    
    
    129,734,209Pipeline and support equipment
    
    
    532,229
    
    
    
    621,481Corporate and other
    
    
    1,817,384
    
    
    
    1,786,691138,737,749
    
    
    
    132,142,381Less accumulated depreciation, depletion, amortization
and write down
    
    
    89,235,011
    
    
    
    84,542,13249,502,738
    
    
    
    47,600,249OTHER ASSETS
    
    
    111,401
    
    
    
    123,970$
    71,329,497
    
    
    $
    61,481,489
  F-4




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2005
    
    
    2004LIABILITIES AND PARTNERS EQUITYCURRENT LIABILITIESAccounts payable
    
    $
    1,624,375
    
    
    $
    776,535Accrued expenses
    
    
    631,571
    
    
    
    482,621Total current liabilities
    
    
    2,255,946
    
    
    
    1,259,156ASSET RETIREMENT OBLIGATIONS
    
    
    1,654,996
    
    
    
    1,167,223COMMITMENTS AND CONTINGENCIESLIMITED PARTNERS EQUITY, SUBJECT TO REPURCHASE
RIGHTAuthorized
 8,000,000 unitsIssued and
outstanding  5,674,678 and 5,690,874 units,
respectively
    
    
    66,630,706
    
    
    
    58,366,937GENERAL PARTNERS EQUITY
    
    
    787,849
    
    
    
    688,173Total partners equity
    
    
    67,418,555
    
    
    
    59,055,110$
    71,329,497
    
    
    $
    61,481,489
  F-5




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##### Table of Contents



2005
    
    
    2004
    
    
    2003REVENUESOil and gas sales
    
    $
    32,557,169
    
    
    $
    25,108,890
    
    
    $
    21,288,143Well management and operating
    
    
    555,093
    
    
    
    560,340
    
    
    
    543,948Other
    
    
    2,089
    
    
    
    1,530
    
    
    
    2,35533,114,351
    
    
    
    25,670,760
    
    
    
    21,834,446DIRECT COST OF REVENUESProduction costs
    
    
    3,563,389
    
    
    
    2,996,361
    
    
    
    2,855,663Well management and operating
    
    
    227,249
    
    
    
    185,097
    
    
    
    220,794Depreciation, depletion and amortization
    
    
    4,805,380
    
    
    
    4,559,746
    
    
    
    4,850,932Accretion expense
    
    
    131,554
    
    
    
    99,181
    
    
    
    92,838Abandonment of oil and gas properties
    
    
    97,983
    
    
    
    40,000
    
    
    
    100,000Total direct cost of revenues
    
    
    8,825,555
    
    
    
    7,880,385
    
    
    
    8,120,227GENERAL AND ADMINISTRATIVE EXPENSE
    
    
    1,511,487
    
    
    
    1,452,586
    
    
    
    1,363,267Total cost of revenues
    
    
    10,337,042
    
    
    
    9,332,971
    
    
    
    9,483,494INCOME FROM OPERATIONS
    
    
    22,777,309
    
    
    
    16,337,789
    
    
    
    12,350,952OTHER INCOMEInterest income
    
    
    271,520
    
    
    
    105,084
    
    
    
    104,587Gain on sale of property and equipment and other assets
    
    
    4,086
    
    
    
    
    
    
    
    36,609275,606
    
    
    
    105,084
    
    
    
    141,196INCOME BEFORE INCOME TAXES AND
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE
    
    
    23,052,915
    
    
    
    16,442,873
    
    
    
    12,492,148INCOME TAXES
    
    
    84,640
    
    
    
    39,576
    
    
    
    69,303INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE
    
    
    22,968,275
    
    
    
    16,403,297
    
    
    
    12,422,845CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE
    
    
    
    
    
    
    
    
    
    
    (471,545
    )NET INCOME
    
    $
    22,968,275
    
    
    $
    16,403,297
    
    
    $
    11,951,300Allocation of Partnership Net IncomeLimited Partners
    
    $
    22,700,247
    
    
    $
    16,212,544
    
    
    $
    11,813,013General Partner
    
    
    268,028
    
    
    
    190,753
    
    
    
    138,287$
    22,968,275
    
    
    $
    16,403,297
    
    
    $
    11,951,300Net income per unit:Before cumulative effect of change in accounting principle
    
    $
    3.99
    
    
    $
    2.84
    
    
    $
    2.14Cumulative effect of change in accounting principle
    
    
    
    
    
    
    
    
    
    
    (0.08
    )Net income per unit
    
    $
    3.99
    
    
    $
    2.84
    
    
    $
    2.06
  F-6




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##### Table of Contents



2005
    
    
    2004
    
    
    2003PARTNERS EQUITY  JANUARY 1
    
    $
    59,055,110
    
    
    $
    55,927,996
    
    
    $
    51,508,256Net income
    
    
    22,968,275
    
    
    
    16,403,297
    
    
    
    11,951,300Cash distributions ($2.50 per unit in 2005, $2.25 per
unit in 2004, $1.25 per unit in 2003)
    
    
    (14,370,636
    )
    
    
    (12,979,302
    )
    
    
    (7,244,313
    )Repurchase and retirement of Units
    
    
    (234,194
    )
    
    
    (296,881
    )
    
    
    (287,247
    )PARTNERS EQUITY  DECEMBER 31
    
    $
    67,418,555
    
    
    $
    59,055,110
    
    
    $
    55,927,996
  F-7




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##### Table of Contents



2005
    
    
    2004
    
    
    2003CASH FLOWS FROM OPERATING ACTIVITIESNet income
    
    $
    22,968,275
    
    
    $
    16,403,297
    
    
    $
    11,951,300Adjustments to reconcile net income to net cash
provided by operating activities:Depreciation, depletion and amortization
    
    
    4,850,207
    
    
    
    4,608,569
    
    
    
    4,897,071Accretion expense
    
    
    131,554
    
    
    
    99,181
    
    
    
    92,838Abandonment of oil and gas properties
    
    
    97,983
    
    
    
    40,000
    
    
    
    100,000Gain on sale of property and equipment
    
    
    (4,086
    )
    
    
    
    
    
    
    (36,609
    )Cumulative effect of change in accounting principle
    
    
    
    
    
    
    
    
    
    
    471,545Changes in assets and liabilities:Accounts receivable
    
    
    (2,522,313
    )
    
    
    (1,623,030
    )
    
    
    (448,865
    )Other current assets
    
    
    (1,382
    )
    
    
    48,863
    
    
    
    14,364Other assets
    
    
    12,569
    
    
    
    (3,294
    )
    
    
    9,303Accounts payable
    
    
    847,840
    
    
    
    54,807
    
    
    
    (24,693
    )Accrued expenses
    
    
    48,950
    
    
    
    30,452
    
    
    
    27,542Total adjustments
    
    
    3,461,322
    
    
    
    3,255,548
    
    
    
    5,102,496Net cash provided by operating activities
    
    
    26,429,597
    
    
    
    19,658,845
    
    
    
    17,053,796CASH FLOWS FROM INVESTING ACTIVITIESProceeds received on receivables from employees
    
    
    41,009
    
    
    
    42,356
    
    
    
    471,545Advances disbursed to employees
    
    
    (124,000
    )
    
    
    (39,500
    )
    
    
    (291,447
    )Purchase of property and equipment
    
    
    (6,400,874
    )
    
    
    (7,963,798
    )
    
    
    (4,875,596
    )Proceeds on sale of property and equipment
    
    
    10,500
    
    
    
    
    
    
    
    82,232Net cash used by investing activities
    
    
    (6,473,365
    )
    
    
    (7,960,942
    )
    
    
    (4,613,266
    )CASH FLOWS FROM FINANCING ACTIVITIESDistributions
    
    
    (14,370,636
    )
    
    
    (12,979,302
    )
    
    
    (7,244,313
    )Repurchase and retirement of Units
    
    
    (234,194
    )
    
    
    (296,881
    )
    
    
    (287,247
    )Net cash used by financing activities
    
    
    (14,604,830
    )
    
    
    (13,276,183
    )
    
    
    (7,531,560
    )NET INCREASE (DECREASE) IN CASH AND
EQUIVALENTS
    
    
    5,351,402
    
    
    
    (1,578,280
    )
    
    
    4,908,970CASH AND
EQUIVALENTS  JANUARY 1
    
    
    8,020,521
    
    
    
    9,598,801
    
    
    
    4,689,831CASH AND
EQUIVALENTS  DECEMBER 31
    
    $
    13,371,923
    
    
    $
    8,020,521
    
    
    $
    9,598,801Supplemental disclosures of cash flow information:Cash paid during the year for:Income taxes
    
    $
    70,000
    
    
    $
    60,000
    
    
    $
    60,000
  F-8




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##### Table of Contents



Note 1. Organization and Summary of Significant Accounting Policies
 A.
    
    Organization  Everflow Eastern Partners, L. P. (Everflow) is a
Delaware limited partnership which was organized in September 1990 to engage in the
business of oil and gas acquisition, exploration, development and production.
Everflow was formed to consolidate the business and oil and gas properties of
Everflow Eastern, Inc. (EEI) and subsidiaries and the oil and gas properties
owned by certain limited partnership and working interest programs managed or
sponsored by EEI (EEI Programs or the Programs).Everflow Management Limited, LLC, an Ohio limited liability company, is the
general partner of Everflow and, as such, is authorized to perform all acts
necessary or desirable to carry out the purposes and conduct of the business of
Everflow. The members of Everflow Management Limited, LLC are Everflow Management
Corporation (EMC), two individuals who are Officers and Directors of EEI and
Sykes Associates, LLC a limited liability company managed by Robert F. Sykes, the
Chairman of the Board of EEI. EMC is an Ohio corporation formed in September 1990
and is the managing member of Everflow Management Limited, LLC.B.
    
    Principles of Consolidation  The consolidated financial statements
include the accounts of Everflow, its wholly-owned subsidiaries, including EEI and
EEIs wholly-owned subsidiaries, and investments in oil and gas drilling and income
partnerships (collectively, the Company) which are accounted for under the
proportional consolidation method. All significant accounts and transactions
between the consolidated entities have been eliminated.C.
    
    Use of Estimates  The preparation of financial statements in
conformity with accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from those estimates.D.
    
    Fair Value of Financial Instruments  The fair values of cash and
equivalents, accounts receivable, accounts payable and other short-term obligations
approximate their carrying values because of the short maturity of these financial
instruments. The carrying values of the Companys long-term obligations
approximate their fair value. In accordance with Statement of Financial Accounting
Standards (SFAS) No. 107, Disclosure About Fair Value of Financial Instruments,
rates available at balance sheet dates to the Company are used to estimate the fair
value of existing obligations.E.
    
    Cash and Equivalents  The Company considers all highly liquid debt
instruments purchased with a maturity of three months or less to be cash
equivalents. The Company maintains at various financial institutions cash and
equivalents which may exceed federally insured amounts and which may, at times,
significantly exceed balance sheet amounts due to float.
 F-9




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##### Table of Contents



Note 1. Organization and Summary of Significant Accounting Policies (Continued)
 F.
    
    Property and Equipment  The Company uses the successful efforts method
of accounting for oil and gas exploration and production activities. Under
successful efforts, costs to acquire mineral interests in oil and gas properties,
to drill and equip development wells and related asset retirement costs are
capitalized. Costs of development wells (on properties the Company has no further
interest in) that do not find proved reserves and geological and geophysical costs
are expensed. The Company has not participated in exploratory drilling and owns no
interest in unproved properties.Capitalized costs of proved properties, after considering estimated dismantlement
and abandonment costs and estimated salvage values, are amortized by the
unit-of-production method based upon estimated proved developed reserves.
Depletion, depreciation and amortization on proved properties amounted to
$4,860,110, $4,603,114 and $4,801,170 for the years ended December 31, 2005, 2004
and 2003, respectively.On sale or retirement of a unit of a proved property (which generally constitutes
the amortization base), the cost and related accumulated depreciation, depletion,
amortization and write down are eliminated from the property accounts, and the
resultant gain or loss is recognized.SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets,
requires that long-lived assets (including oil and gas properties) and certain
identifiable intangibles be reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable. Everflow utilizes a field by field basis for assessing impairment of
its oil and gas properties. The Company wrote down oil and gas properties by
approximately $98,000, $40,000 and $100,000 during 2005, 2004 and 2003,
respectively, to provide for impairment on certain of its oil and gas properties.Pipeline and support equipment and other corporate property and equipment are
recorded at cost and depreciated principally on the straight-line method over
their estimated useful lives (pipeline and support equipment  10 to 15 years,
other corporate equipment  3 to 7 years, other corporate property  building and
improvements with a cost of $1,209,523  40 years). Depreciation on pipeline and
support equipment and other corporate property and equipment amounted to $121,651,
$104,636 and $95,901 for the years ended December 31, 2005, 2004 and 2003,
respectively.Maintenance and repairs of property and equipment are expensed as incurred. Major
renewals and improvements are capitalized, and the assets replaced are retired.
 F-10




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##### Table of Contents



Note 1. Organization and Summary of Significant Accounting Policies (Continued)
 G.
    
    Asset Retirement Obligations  In 2003, the Company adopted SFAS No.
143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires the fair
value of a liability for an asset retirement obligation to be recognized in the
period in which it is incurred if a reasonable estimate of fair value can be made.
For the Company, these obligations include plugging and abandonment of oil and gas
wells and associated pipelines and equipment. The associated asset retirement
costs are capitalized as part of the carrying amount of the long-lived asset.
Historically, and consistent with industry practice, the Company determined that
the cost of plugging and abandoning its oil and gas properties would be offset by
proceeds received from salvage. The Company recorded a non-cash charge of
approximately $500,000 as the cumulative effect of a change in accounting
principle, an increase to oil and gas properties of approximately $400,000 and a
non-current liability of approximately $900,000 in connection with the adoption of
SFAS No. 143.The estimated liability is based on historical experience in plugging and
abandoning wells, estimated remaining lives of those wells based on reserves
estimates, estimates of the external cost to plug and abandon the wells in the
future and federal and state regulatory requirements. The liability is discounted
using an assumed credit-adjusted risk-free interest rate. Revisions to the
liability will likely occur due to: changes in estimates of plugging and
abandonment costs; changes in estimated remaining lives of the wells; changes in
federal or state regulations regarding plugging and abandonment requirements; and
other factors. At December 31, 2005, the Company made revisions in estimates of
plugging costs, discount rate, inflation rate and remaining lives of wells.The Company has no assets legally restricted for purposes of settling its asset
retirement obligations. The Company has determined that there are no other
material retirement obligations associated with tangible long-lived assets.The schedule below is a reconciliation of the Companys liability for the years
ended December 31:
 2005
    
    
    2004Beginning of Period
    
    $
    1,267,223
    
    
    $
    1,134,685Liabilities incurred
    
    
    37,029
    
    
    
    33,357Liabilities settled
    
    
    
    
    
    
    Accretion expense
    
    
    131,554
    
    
    
    99,181Revisions in estimated cash flows
    
    
    419,190
    
    
    
    Total
    
    $
    1,854,996
    
    
    $
    1,267,223
 At December 31, 2005 and 2004, the asset retirement obligations are included
in accrued expenses (current portion) and asset retirement obligations
(non-current portion) in the Companys consolidated balance sheets. The current
portion of the asset retirement obligations were $200,000 and $100,000 at December
31, 2005
and 2004, respectively.
 F-11




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##### Table of Contents



Note 1. Organization and Summary of Significant Accounting Policies (Continued)
 H.
    
    Revenue Recognition  The Company recognizes revenue from oil and gas
production as it is extracted and sold from the properties. Other revenue is
recognized at the time it is earned and the Company has a contractual right to such
revenue.The Company participates (and may act as drilling contractor) with unaffiliated
joint venture partners and employees in the drilling, development and operation of
jointly owned oil and gas properties. Each owner, including the Company, has an
undivided interest in the jointly owned property(ies). Generally, the joint
venture partners and employees participate on the same drilling/development cost
basis as the Company and, therefore, no revenue, expense or income is recognized
on the drilling and development of the properties. Accounts receivable from joint
venture partners and employees consist principally of drilling and development
costs the Company has advanced or incurred on behalf of joint venture partners and
employees. The Company earns and receives monthly management and operating fees
from certain joint venture partners and employees after the properties are
completed and placed into production.I.
    
    Income Taxes  Everflow is not a tax-paying entity and the net taxable
income or loss, other than the taxable income or loss allocable to EEI, which is a
C corporation owned by Everflow, will be allocated directly to its respective
partners. The Company is not able to determine the net difference between the tax
bases and the reported amounts of Everflows assets and liabilities due to separate
tax elections that were made by owners of the working interests and limited
partnership interests that comprised Programs.As referred to in Note 4, EEI and its subsidiaries account for income taxes under
SFAS No. 109, Accounting for Income Taxes. Income taxes are provided for all
items (as they relate to EEI and its subsidiaries) in the Consolidated Statements
of Income regardless of the period when such items are reported for income tax
purposes. SFAS No. 109 provides that deferred tax assets and liabilities be
recognized for temporary differences between the financial reporting basis and tax
basis of certain of EEIs and its subsidiaries assets and liabilities. In
addition, SFAS No. 109 requires that deferred tax assets and liabilities be
measured using enacted tax rates expected to apply to taxable income in the years
in which the temporary differences are expected to be recovered or settled. The
impact on deferred taxes of changes in tax rates and laws, if any, is reflected in
the financial statements in the period of enactment. In some situations, SFAS No.
109 permits the recognition of expected benefits of utilizing net operating loss
and tax credit carryforwards.J.
    
    Allocation of Income and Per Unit Data  Under the terms of the limited
partnership agreement, initially, 99% of revenues and costs were allocated to the
unitholders (the limited partners) and 1% of revenues and costs were allocated to
the general partner. The allocation changes as unitholders elect to exercise the
repurchase right (see Note 3).
 F-12




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##### Table of Contents



Note 1. Organization and Summary of Significant Accounting Policies (Continued)
 J.
    
    Allocation of Income and Per Unit Data (Continued)Earnings and distributions per limited partner Unit have been computed based on
the weighted average number of Units outstanding during the year for each year
presented. Average outstanding Units for earnings and distributions per Unit
calculations amount to 5,682,776, 5,702,806 and 5,731,756 in 2005, 2004 and 2003,
respectively.K.
    
    New Accounting Standards  No new accounting pronouncement issued or
effective during 2005 has had or is expected to have a material impact on the
consolidated financial statements.L.
    
    Reclassifications  Certain prior year amounts have been reclassified
to conform with the current years presentation.
 Note 2. Credit Facilities and Long-Term Debt
 The Company had a revolving line of credit that expired on May 31, 2003. The Company
anticipates entering into a commitment for a new line of credit agreement in the event
funds are needed for the purpose of funding the annual repurchase right (see Note 3).
The new line of credit would be utilized in the event the Company receives tenders
pursuant to the repurchase right in excess of cash on hand.There were no borrowings outstanding during 2005 and 2004. The Company would be exposed
to market risk from changes in interest rates if it funds its future operations through
long-term or short-term borrowings.
 Note 3. Partners Equity
 Units represent limited partnership interests in Everflow. The Units are transferable
subject only to the approval of any transfer by Everflow Management Limited, LLC and to
the laws governing the transfer of securities. The Units are not listed for trading on
any securities exchange nor are they quoted in the automated quotation system of a
registered securities association. However, unitholders have an opportunity to require
Everflow to repurchase their Units pursuant to the repurchase right.
 F-13




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##### Table of Contents



Note 3. Partners Equity (Continued)
 Under the terms of the limited partnership agreement, initially, 99% of revenues and
costs are allocated to the unitholders (the limited partners) and 1% of revenues and
costs are allocated to the general partner. Such allocation has changed and will change
in the future due to unitholders electing to exercise the repurchase right.The partnership agreement provides that Everflow will repurchase for cash up to 10% of
the then outstanding Units, to the extent unitholders offer Units to Everflow for
repurchase pursuant to the repurchase right. The repurchase right entitles any
unitholder, between May 1 and June 30 of each year, to notify Everflow that the
unitholder elects to exercise the repurchase right and have Everflow acquire certain or
all Units. The price to be paid for any such Units is calculated based upon the audited
financial statements of the Company as of December 31 of the year prior to the year in
which the repurchase right is to be effective and independently prepared reserve
reports. The price per Unit equals 66% of the adjusted book value of the Company
allocable to the Units, divided by the number of Units outstanding at the beginning of
the year in which the applicable repurchase right is to be effective less all interim
cash distributions received by a unitholder. The adjusted book value is calculated by
adding partners equity, the standardized measure of discounted future net cash flows
and the tax effect included in the standardized measure and subtracting from that sum
the carrying value of oil and gas properties (net of undeveloped lease costs). If more
than 10% of the then outstanding Units are tendered during any period during which the
repurchase right is to be effective, the investors Units tendered shall be prorated for
purposes of calculating the actual number of Units to be acquired during any such
period. The price associated with the repurchase right, based upon the December 31,
2005 calculation, is estimated to be $22.87 per Unit, net of the distributions ($1.50
per Unit in total) expected to be made in January and April 2006.Units repurchased pursuant to the repurchase right, for each of the four years in the
period ended December 31, 2005, are as follows:
 Per UnitCalculated
    
    
    
    
    
    
    
    
    
    
    
    
    
    UnitsPrice for
    
    Less
    
    
    
    
    
    
    
    
    
    OutstandingRepurchase
    
    Interim
    
    Net
    
    # of Units
    
    FollowingYear
    
    Right
    
    Distributions
    
    Price Paid
    
    Repurchased
    
    Repurchase2002
    
    $
    6.16
    
    
    $
    .50
    
    
    $
    5.66
    
    
    
    22,401
    
    
    
    5,748,7732003
    
    $
    8.94
    
    
    $
    .50
    
    
    $
    8.44
    
    
    
    34,034
    
    
    
    5,714,7392004
    
    $
    13.44
    
    
    $
    1.00
    
    
    $
    12.44
    
    
    
    23,865
    
    
    
    5,690,8742005
    
    $
    15.46
    
    
    $
    1.00
    
    
    $
    14.46
    
    
    
    16,196
    
    
    
    5,674,678
 F-14




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##### Table of Contents



Note 4. Provision for Income Taxes
 A reconciliation between taxes computed at the Federal statutory rate and the effective
tax rate in the statements of income follows:
 Year Ended December 31,2005
    
    
    2004
    
    
    2003Amount
    
    
    %
    
    
    Amount
    
    
    %
    
    
    Amount
    
    
    %Provision based on the
statutory rate (for taxable
income up to $10,000,000)
    
    $
    7,838,000
    
    
    
    34.0
    
    
    $
    5,591,000
    
    
    
    34.0
    
    
    $
    4,087,000
    
    
    
    34.0Tax effect of:Non-taxable status of the
Programs and Everflow
    
    
    (7,301,000
    )
    
    
    (31.7
    )
    
    
    (5,226,000
    )
    
    
    (31.8
    )
    
    
    (3,827,000
    )
    
    
    (31.8
    )Excess statutory depletion
    
    
    (99,000
    )
    
    
    (0.4
    )
    
    
    (80,000
    )
    
    
    (0.5
    )
    
    
    (70,000
    )
    
    
    (0.6
    )Graduated tax rates, state
income tax, tax credits
and other  net
    
    
    (353,360
    )
    
    
    (1.5
    )
    
    
    (245,424
    )
    
    
    (1.5
    )
    
    
    (120,697
    )
    
    
    (1.0
    )Total
    
    $
    84,640
    
    
    
    0.4
    
    
    $
    39,576
    
    
    
    0.2
    
    
    $
    69,303
    
    
    
    0.6
 As referred to in Note 1, EEI and its subsidiaries account for current and deferred
income taxes under the provisions of SFAS No. 109. Items giving rise to deferred taxes
consist of temporary differences arising from differences in financial reporting and tax
reporting methods for EEIs proved properties. At December 31, 2005 and 2004, these
deferred tax items resulted in deferred tax liabilities of $469,000 and $506,000,
respectively. These liabilities have been fully offset by deferred tax assets resulting
from the tax benefit of EEIs percentage depletion and in 2005 tax credit carryovers.
EEI has federal tax credit carryforwards generated from payment of alternative minimum
tax (AMT credits) in prior years. Prior to 2005, due to the anticipated minimum
utilization of the AMT credits, the Company recorded no tax benefit related to the
credits. Due to higher gas prices which significantly increased EEIs net taxable
income, EEI now anticipates utilizing its AMT credits and has recorded the tax benefit
in the current year. At December 31, 2005 and 2004, EEI had percentage depletion
deduction carryforwards for tax purposes of approximately $654,000 and $1,311,000,
respectively. At December 31, 2005 and 2004, EEI had AMT credit carryforwards for tax
purposes of approximately $177,000 and $276,000, respectively. These carryforwards can
be carried forward indefinitely.
 Note 5. Retirement Plan
 The Company has a defined contribution plan pursuant to Section 401(k) of the Internal
Revenue Code for all employees who have reached the age of 21 and completed one year of
service. The Company matches employees contributions to the 401(k) Retirement Savings
Plan as annually determined by EMCs Board of Directors. Additionally, the plan has a
profit sharing component which provides for contributions to the plan at the discretion
of EMCs Board of Directors. Amounts contributed to the plan vest
immediately. The Companys total matching and profit sharing contributions to the plan
amounted to $175,788, $167,220 and $169,035 for the years ended December 31, 2005, 2004
and 2003, respectively.
 F-15




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##### Table of Contents



Note 6. Related Party Transactions
 The Companys Officers, Directors, Affiliates and certain employees have frequently
participated, and will likely participate in the future, as working interest owners in
wells in which the Company has an interest. Frequently, the Company has loaned the
funds necessary for certain employees to participate in the drilling and development of
such wells. At December 31, 2005, the loans accrue interest at 7.25% and are expected
to be paid from production revenues attributable to such interests or through joint
interest assessments.
 Note 7. Business Segments, Risks and Major Customers
 The Company operates exclusively in the United States, almost entirely in Ohio and
Pennsylvania, in the acquisition, exploration, development and production of oil and
gas.The Company operates in an environment with many financial risks, including, but not
limited to, the ability to acquire additional economically recoverable oil and gas
reserves, the inherent risks of the search for, development of and production of oil and
gas, the ability to sell oil and gas at prices which will provide attractive rates of
return, the volatility and seasonality of oil and gas production and prices, and the
highly competitive and, at times, seasonal nature of the industry and worldwide economic
conditions. The Companys ability to expand its reserve base and diversify its
operations is also dependent upon the Companys ability to obtain the necessary capital
through operating cash flow, borrowings or equity offerings. Various federal, state and
governmental agencies are considering, and some have adopted, laws and regulations
regarding environmental protection which could adversely affect the proposed business
activities of the Company. The Company cannot predict what effect, if any, current and
future regulations may have on the operations of the Company.Management of the Company continually evaluates whether the Company can develop oil and
gas properties at historical levels given current industry and market conditions. If
the Company is unable to do so, it could be determined that it is in the best interests
of the Company and its unitholders to reorganize, liquidate or sell the Company.
However, management cannot predict whether any sale transaction will be a viable
alternative for the Company in the immediate future.Gas sales accounted for 88%, 89% and 90% of total oil and gas sales in 2005, 2004 and
2003, respectively. Approximate percentages of total oil and gas sales from significant
purchasers for the years ended December 31, 2005, 2004 and 2003, respectively, were as
follows:
 Customer
    
    2005
    
    2004
    
    2003Dominion Field Services, Inc., its affiliates and
its predecessors (Dominion)
    
    
    40
    %
    
    
    46
    %
    
    
    48
    %Ergon Oil Purchasing, Inc. (Ergon Oil)
    
    
    12
    
    
    
    10
    
    
    
    10Interstate Gas Supply, Inc. (IGS)
    
    
    18
    
    
    
    21
    
    
    
    2370
    %
    
    
    77
    %
    
    
    81
    %
 F-16




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##### Table of Contents



Note 7. Business Segments, Risks and Major Customers (Continued)
 The Companys production accounts receivable result from sales of natural gas and crude
oil. A significant portion of the Companys production accounts receivable is due from
the Companys major customers. The Company does not view such concentration as an
unusual credit risk. However, the Company does not require collateral from its
customers and could incur losses if its customers fail to pay. As a result of
managements review of current and historical credit losses and economic activity, a
valuation allowance was not deemed necessary at December 31, 2005 and 2004. The Company
expects that Dominion, Ergon Oil and IGS will be the only major customers in 2006.The Company has numerous short-term contracts, which obligate Dominion to purchase, and
the Company to sell and deliver, certain natural gas production from the Companys wells
throughout the contract periods. A summary of significant gas purchase contracts,
including weighted average pricing provisions, with Dominion follows:
 Jan
    
    Feb
    
    Mar
    
    Apr
    
    May
    
    Jun2006
    
    2006
    
    2006
    
    2006
    
    2006
    
    2006MCF
    
    
    140,000
    
    
    
    140,000
    
    
    
    140,000
    
    
    
    90,000
    
    
    
    90,000
    
    
    
    130,000Price
    
    $
    7.65
    
    
    $
    7.65
    
    
    $
    7.65
    
    
    $
    7.45
    
    
    $
    7.45
    
    
    $
    7.21Jul
    
    Aug
    
    Sep
    
    Oct
    
    Nov
    
    Dec2006
    
    2006
    
    2006
    
    2006
    
    2006
    
    2006MCF
    
    
    90,000
    
    
    
    90,000
    
    
    
    90,000
    
    
    
    90,000
    
    
    
    140,000
    
    
    
    120,000Price
    
    $
    7.45
    
    
    $
    7.45
    
    
    $
    7.45
    
    
    $
    7.45
    
    
    $
    10.21
    
    
    $
    9.89Jan
    
    Feb
    
    Mar
    
    Apr
    
    May
    
    Jun2007
    
    2007
    
    2007
    
    2007
    
    2007
    
    2007MCF
    
    
    120,000
    
    
    
    120,000
    
    
    
    120,000
    
    
    
    80,000
    
    
    
    80,000
    
    
    
    100,000Price
    
    $
    9.89
    
    
    $
    9.89
    
    
    $
    9.89
    
    
    $
    9.78
    
    
    $
    9.78
    
    
    $
    9.81Jul
    
    Aug
    
    Sep
    
    Oct2007
    
    2007
    
    2007
    
    2007MCF
    
    
    80,000
    
    
    
    80,000
    
    
    
    80,000
    
    
    
    80,000Price
    
    $
    9.78
    
    
    $
    9.78
    
    
    $
    9.78
    
    
    $
    9.78
 F-17




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##### Table of Contents



Note 7. Business Segments, Risks and Major Customers (Continued)
 The Company also has a short-term contract with IGS, which obligates IGS to purchase,
and the Company to sell and deliver, certain quantities of natural gas production on a
monthly basis throughout the contract periods. A summary of significant gas purchase
contracts, including weighted average pricing provisions, with IGS follows:
 Jan
    
    Feb
    
    Mar
    
    Apr
    
    May
    
    Jun2006
    
    2006
    
    2006
    
    2006
    
    2006
    
    2006MCF
    
    
    80,000
    
    
    
    80,000
    
    
    
    80,000
    
    
    
    60,000
    
    
    
    60,000
    
    
    
    80,000Price
    
    $
    7.76
    
    
    $
    7.76
    
    
    $
    7.76
    
    
    $
    7.49
    
    
    $
    7.49
    
    
    $
    7.27
 Jul
    
    Aug
    
    Sep
    
    Oct
    
    Nov
    
    Dec2006
    
    2006
    
    2006
    
    2006
    
    2006
    
    2006MCF
    
    
    60,000
    
    
    
    60,000
    
    
    
    60,000
    
    
    
    60,000
    
    
    
    90,000
    
    
    
    70,000Price
    
    $
    7.49
    
    
    $
    7.49
    
    
    $
    7.49
    
    
    $
    7.49
    
    
    $
    10.75
    
    
    $
    10.40
 Jan
    
    Feb
    
    Mar
    
    Apr
    
    May
    
    Jun2007
    
    2007
    
    2007
    
    2007
    
    2007
    
    2007MCF
    
    
    70,000
    
    
    
    70,000
    
    
    
    70,000
    
    
    
    40,000
    
    
    
    40,000
    
    
    
    60,000Price
    
    $
    10.40
    
    
    $
    10.40
    
    
    $
    10.40
    
    
    $
    9.57
    
    
    $
    9.57
    
    
    $
    9.57
 Jul
    
    Aug
    
    Sep
    
    Oct2007
    
    2007
    
    2007
    
    2007MCF
    
    
    40,000
    
    
    
    40,000
    
    
    
    40,000
    
    
    
    40,000Price
    
    $
    9.57
    
    
    $
    9.57
    
    
    $
    9.57
    
    
    $
    9.57
 As detailed above, the price paid for natural gas purchased by Dominion and IGS
varies based on quantities locked in by the Company from time to time. Natural gas sold
under these contracts in excess of the locked in prices are sold at the months closing
price plus basis adjustments, as per the contracts. As of December 31, 2005, natural
gas purchased by Dominion covers production from approximately 490 gross wells, while
natural gas purchased by IGS covers production from approximately 220 gross wells.
Production from the Dominion and IGS contract wells comprises approximately 68% of the
Companys natural gas sales.
 Note 8. Commitments and Contingencies
 Everflow paid a dividend in January 2006 of $.75 per Unit. The distribution amounted to
approximately $4,306,000.As described in Note 7, the Company has significant natural gas delivery commitments to
Dominion and IGS, its major customers. Management believes the Company can meet its
delivery commitments based on estimated production. If, however, the Company cannot
meet its delivery commitments, it will purchase gas at market prices to meet such
commitments which will result in a gain or loss for the difference between the delivery
commitment price and the price the Company is able to purchase the gas for redelivery
(resale) to its customers.
 F-18




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Note 9. Selected Quarterly Financial Data (Unaudited)
 The following is a summary of selected quarterly financial data (unaudited) for the
years ended December 31, 2005 and 2004:
 Quarters EndedMarch 31
    
    June 30
    
    September 30
    
    December 312005Revenues
    
    $
    5,813,500
    
    
    $
    7,379,613
    
    
    $
    8,053,619
    
    
    $
    11,867,619Income from operations
    
    
    3,414,384
    
    
    
    5,059,288
    
    
    
    5,331,105
    
    
    
    8,972,532Net income
    
    
    3,461,021
    
    
    
    5,116,275
    
    
    
    5,374,890
    
    
    
    9,016,089Net income per unit
    
    
    0.60
    
    
    
    0.89
    
    
    
    0.94
    
    
    
    1.56
 Quarters EndedMarch 31
    
    June 30
    
    September 30
    
    December 312004Revenues
    
    $
    4,779,149
    
    
    $
    6,253,062
    
    
    $
    6,812,143
    
    
    $
    7,826,406Income from operations
    
    
    2,334,997
    
    
    
    4,082,091
    
    
    
    4,202,777
    
    
    
    5,717,924Net income
    
    
    2,361,722
    
    
    
    4,105,740
    
    
    
    4,197,051
    
    
    
    5,738,784Net income per unit
    
    
    0.41
    
    
    
    0.71
    
    
    
    0.73
    
    
    
    0.99
 Quarterly operating results are not necessarily representative of operations for a
full year for various reasons, including the volatility and seasonality of oil and gas
production and prices, the highly competitive and, at times, seasonal nature of the oil
and gas industry and worldwide economic conditions.
 Note 10. Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited)
 The following supplemental unaudited oil and gas information is required by SFAS No. 69,
Disclosures About Oil and Gas Producing Activities.
 F-19




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##### Table of Contents



Note 10. Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) (Continued)
 The tables on the following pages set forth pertinent data with respect to the Companys
oil and gas properties, all of which are located within the continental United States.
 
 Years ended December 31,2005
    
    
    2004
    
    
    2003Proved oil and gas properties
    
    $
    136,388,136
    
    
    $
    129,734,209
    
    
    $
    122,422,677Pipeline and support equipment
    
    
    532,229
    
    
    
    621,481
    
    
    
    498,179136,920,365
    
    
    
    130,355,690
    
    
    
    122,920,856Accumulated depreciation, depletion,
amortization and write down
    
    
    88,767,760
    
    
    
    84,127,102
    
    
    
    80,018,796Net capitalized costs
    
    $
    48,152,605
    
    
    $
    46,228,588
    
    
    $
    42,902,060
  Years ended December 31,2005
    
    
    2004
    
    
    2003Property acquisition costs
    
    $
    321,395
    
    
    $
    318,155
    
    
    $
    461,803Development costs
    
    
    6,017,543
    
    
    
    7,384,951
    
    
    
    4,239,552
 In 2005, 2004 and 2003, development costs include the purchase of approximately
$-0-, $21,000 and $-0-, respectively, of producing oil and gas properties.
 F-20




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Note 10. Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) (Continued)
  Years ended December 31,2005
    
    
    2004
    
    
    2003Oil and gas sales
    
    $
    32,557,169
    
    
    $
    25,108,890
    
    
    $
    21,288,143Production costs
    
    
    (3,563,389
    )
    
    
    (2,996,361
    )
    
    
    (2,855,663
    )Depreciation, depletion and
amortization
    
    
    (4,805,380
    )
    
    
    (4,559,746
    )
    
    
    (4,850,932
    )Accretion expense
    
    
    (131,554
    )
    
    
    (99,181
    )
    
    
    (92,838
    )Abandonment of oil and gas properties
    
    
    (97,983
    )
    
    
    (40,000
    )
    
    
    (100,000
    )23,958,863
    
    
    
    17,413,602
    
    
    
    13,388,710Income tax expense
    
    
    260,000
    
    
    
    100,000
    
    
    
    80,000Results of operations for oil and gas
producing activities (excluding
corporate overhead and financing
costs)
    
    $
    23,698,863
    
    
    $
    17,313,602
    
    
    $
    13,308,710
 Income tax expense was computed using statutory tax rates and reflects permanent
differences that are reflected in the Companys consolidated income tax expense for the
year.
 F-21




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##### Table of Contents



Note 10. Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) (Continued)
  Oil
    
    
    Gas(BBLS)
    
    
    (MCF)Balance, January 1, 2003
    
    
    699,000
    
    
    
    43,307,000Extensions, discoveries and other
additions
    
    
    9,000
    
    
    
    1,509,000Production
    
    
    (76,000
    )
    
    
    (4,053,000
    )Revision of previous estimates
    
    
    71,000
    
    
    
    6,306,000Balance, December 31, 2003
    
    
    703,000
    
    
    
    47,069,000Extensions, discoveries and other
additions
    
    
    65,000
    
    
    
    3,194,000Production
    
    
    (72,000
    )
    
    
    (3,932,000
    )Revision of previous estimates
    
    
    86,000
    
    
    
    3,019,000Balance, December 31, 2004
    
    
    782,000
    
    
    
    49,350,000Extensions, discoveries and other
additions
    
    
    32,000
    
    
    
    1,355,000Production
    
    
    (72,000
    )
    
    
    (3,878,000
    )Revision of previous estimates
    
    
    61,000
    
    
    
    4,216,000Balance, December 31, 2005
    
    
    803,000
    
    
    
    51,043,000PROVED DEVELOPED RESERVES:December 31, 2002
    
    
    699,000
    
    
    
    43,307,000December 31, 2003
    
    
    703,000
    
    
    
    47,069,000December 31, 2004
    
    
    782,000
    
    
    
    49,350,000December 31, 2005
    
    
    803,000
    
    
    
    51,043,000
 The Company has not determined proved reserves associated with its proved
undeveloped acreage. At December 31, 2005 and 2004, the Company had 255 and 360 net
proved undeveloped acres, respectively. The carrying cost of the proved undeveloped
acreage that is included in proved properties amounted to $89,741 and $188,869 at
December 31, 2005 and 2004, respectively.
 F-22




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##### Table of Contents



Note 10. Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) (Continued)
 
 December 31,2005
    
    
    2004
    
    
    2003(Thousands of Dollars)Future cash inflows from sales of oil
and gas
    
    $
    566,186
    
    
    $
    352,486
    
    
    $
    311,816Future production and development
costs
    
    
    139,946
    
    
    
    105,807
    
    
    
    95,721Future asset retirement obligations, net of
salvage
    
    
    9,145
    
    
    
    3,509
    
    
    
    3,151Future income tax expense
    
    
    8,997
    
    
    
    5,133
    
    
    
    4,841Future net cash flows
    
    
    408,098
    
    
    
    238,037
    
    
    
    208,103Effect of discounting future net cash
flows at 10% per annum
    
    
    219,835
    
    
    
    118,948
    
    
    
    106,260Standardized measure of discounted
future net cash flows
    
    $
    188,263
    
    
    $
    119,089
    
    
    $
    101,843
 
 Years Ended December 31,2005
    
    
    2004
    
    
    2003(Thousands of Dollars)Balance, beginning of year
    
    $
    119,089
    
    
    $
    101,843
    
    
    $
    67,934Extensions, discoveries and other
additions
    
    
    6,380
    
    
    
    9,487
    
    
    
    3,672Development costs incurred
    
    
    1,436
    
    
    
    349
    
    
    
    162Revision of quantity estimates
    
    
    15,809
    
    
    
    8,456
    
    
    
    15,134Sales of oil and gas, net of production
costs
    
    
    (28,994
    )
    
    
    (22,113
    )
    
    
    (18,432
    )Net change in income taxes
    
    
    (1,534
    )
    
    
    (203
    )
    
    
    (933
    )Net changes in prices and production
costs
    
    
    63,400
    
    
    
    10,504
    
    
    
    25,894Accretion of discount
    
    
    11,909
    
    
    
    10,184
    
    
    
    6,793Other
    
    
    768
    
    
    
    582
    
    
    
    1,619Balance, end of year
    
    $
    188,263
    
    
    $
    119,089
    
    
    $
    101,843
 F-23




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##### Table of Contents



Note 10. Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) (Continued)
 The estimated future cash flows are determined based on year-end prices for crude oil,
current allowable prices (adjusted for periods beyond the contract period to year-end
market prices) applicable to expected natural gas production, estimated production of
proved crude oil and natural gas reserves, estimated future production and development
costs of reserves and future retirement obligations (net of salvage), based on current
economic conditions, and the estimated future income tax expense, based on year-end
statutory tax rates (with consideration of future tax rates already legislated) to be
incurred on pretax net cash flows less the tax basis of the properties involved. Such
cash flows are then discounted using a 10% rate.The methodology and assumptions used in calculating the standardized measure are those
required by SFAS No. 69. It is not intended to be representative of the fair market
value of the Companys proved reserves. The valuation of revenues and costs does not
necessarily reflect the amounts to be received or expended by the Company. In addition
to the valuations used, numerous other factors are considered in evaluating known and
prospective oil and gas reserves.
 F-24




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##### Table of Contents



ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
  
 ITEM 9A. CONTROLS AND PROCEDURES
   
 ITEM 9B. OTHER INFORMATION
  32




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PART III
 
 ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
    Directors and Officers of EEI and EMC
 Positions and
    
    Positions andName
    
    Age
    
    Offices with EEI
    
    Offices with EMCRobert F. Sykes
    
    
    82
    
    
    Chairman of the Board
    
    Chairman of the Board
and DirectorThomas L. Korner
    
    
    52
    
    
    President and Director
    
    President and DirectorWilliam A. Siskovic
    
    
    50
    
    
    Vice President, Secretary-
Treasurer, Principal
Financial and Accounting
Officer and Director
    
    Vice President, Secretary-
Treasurer, Principal
Financial and Accounting
Officer and Director
  33




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##### Table of Contents



Robert F. Sykes
 Thomas L. Korner
 William A. Siskovic
 34




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##### Table of Contents



Compliance to Section 16(a) of the Exchange Act
  
 ITEM 11. EXECUTIVE COMPENSATION
    Annual CompensationOtherAnnual
    
    All OtherName and
    
    
    
    
    
    
    
    
    
    
    
    
    
    Compen-
    
    Compen-Principal Position
    
    Year
    
    Salary
    
    Bonus
    
    sation (2)
    
    sation (1)Thomas L. Korner
    
    
    2005
    
    
    $
    100,800
    
    
    $
    77,500
    
    
    $
    3,193
    
    
    $
    29,002President
    
    
    2004
    
    
    
    100,800
    
    
    
    86,000
    
    
    
    3,271
    
    
    
    28,8522003
    
    
    
    96,600
    
    
    
    76,000
    
    
    
    3,030
    
    
    
    27,966William A. Siskovic
    
    
    2005
    
    
    $
    100,800
    
    
    $
    77,500
    
    
    $
    3,064
    
    
    $
    29,002Vice President and
    
    
    2004
    
    
    
    100,800
    
    
    
    86,000
    
    
    
    2,538
    
    
    
    28,852Principal Financial and
    
    
    2003
    
    
    
    96,000
    
    
    
    76,000
    
    
    
    1,891
    
    
    
    27,992Accounting Officer
 
 No Named Executive Officer received personal benefits or perquisites during 2005, 2004 and 2003 in
excess of the lesser of $50,000 or 10% of his aggregate salary and bonus.(1)
    
    Includes amounts contributed under the Companys 401(K) Retirement Savings Plan. The
Company matched employees contributions to the 401(K) Retirement Savings Plan to the extent
of 100% of the first 6% of a participants salary reduction. Also includes amounts
contributed under the profit sharing component of the Companys 401(K) Retirement Savings
Plan. The amounts attributable to the Companys matching and profit sharing contributions
vest immediately.(2)
    
    Includes amounts considered taxable wages with respect to the Companys Group Term
Life Insurance Plan. 35




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##### Table of Contents



ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
   BENEFICIAL OWNERSHIP OF UNITS IN THE COMPANY,
EVERFLOW MANAGEMENT LIMITED, LLC AND EMC
 PercentageInterest inPercentage
    
    Everflow
    
    PercentageName
    
    Units
    
    of Units
    
    Management
    
    Interest inof Holder
    
    in Company
    
    in Company(1)
    
    Limited, LLC(2)
    
    EMCRobert F. Sykes(3)
    
    
    1,056,464
    
    
    
    18.56
    
    
    
    66.6666
    
    
    
    66.6666Thomas L. Korner
    
    
    138,575
    
    
    
    2.44
    
    
    
    16.6667
    
    
    
    16.6667William A. Siskovic
    
    
    71,731
    
    
    
    1.26
    
    
    
    16.6667
    
    
    
    16.6667All officers and directors as
a group (3 persons in EMC)
    
    
    1,266,770
    
    
    
    22.32
    
    
    
    100.0000
    
    
    
    100.0000
 
 (1)
    
    Does not include the interest in the Company owned indirectly by such
individuals as a result of their ownership in (i) the General Partner (based on its 1.17%
interest in the Company) or (ii) EMC (based on EMCs 1% managing members interest in the
General Partner).(2)
    
    Includes the interest in the General Partner owned indirectly by such
individuals as a result of their share ownership in EMC resulting from EMCs 1% managing
members interest in the General Partner.(3)
    
    Includes 732,855 Units held by Sykes Associates, LLC, a New York limited
liability company comprised of Mr. Sykes as managing member, his wife and four adult children
as members, 162,462 Units of the Company held by the Robert F. Sykes Annuity Trust and 161,147
Units held by the Catherine Sykes Annuity Trust. 36




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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
   
 ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
  December 31,2005
    
    
    2004Audit fees
    
    $
    107,020
    
    
    $
    104,517Audit related fees
    
    
    -0-
    
    
    
    -0-Tax fees
    
    
    -0-
    
    
    
    -0-All other fees
    
    
    -0-
    
    
    
    -0-Total
    
    $
    107,020
    
    
    $
    104,517
  37




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##### Table of Contents



PART IV
 
 ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
   Page(s)Report of Independent Registered Public Accounting Firm
    
    F-3Balance Sheets
    
    F-4 - F-5Statements of Income
    
    F-6Statements of Partners Equity
    
    F-7Statements of Cash Flows
    
    F-8Notes to Financial Statements
    
    F-9  F-24
     Reports on Form 8-K
  Exhibits required by Item 601 of Regulation S-K
  38




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##### Table of Contents



SIGNATURES
   By:
    
    EVERFLOW MANAGEMENT LIMITED, LLCGeneral PartnerBy:
    
    EVERFLOW MANAGEMENT CORPORATIONManaging Member
 By:
    
    /s/ Robert F. Sykes

Robert F. Sykes
    
    Director
    
    March 31, 2006By:
    
    /s/ Thomas L. Korner

Thomas L. Korner
    
    President and Director
    
    March 31, 2006By:
    
    /s/ William A. Siskovic

William A. Siskovic
    
    Vice President, Secretary-Treasurer
and
Director (principal
financial and accounting
officer)
    
    March 31, 2006




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##### Table of Contents



Exhibit Index
 Exhibit No.
    
    Description3.1
    
    Certificate of Limited Partnership of the Registrant
dated September 13, 1990, as filed with the Delaware
Secretary of State on September 14, 1990
    
    
    (1
    )3.2
    
    Form of Agreement of Limited Partnership of the
Registrant
    
    
    (1
    )3.3
    
    General Partnership Agreement of Everflow
Management Company
    
    
    (1
    )3.4
    
    Articles of Incorporation of Everflow Management
Corporation
    
    
    (1
    )3.5
    
    Code of Regulations of Everflow Management
Corporation
    
    
    (1
    )3.6
    
    Shareholders Agreement for Everflow Management
Corporation
    
    
    (1
    )10.1
    
    Credit Agreement dated January 19, 1995 between
Everflow Eastern, Inc. and Everflow Eastern Partners, L.P.
and Bank One, Texas, National Association
    
    
    (2
    )10.2
    
    Operating facility lease dated October 3, 1995 between
Everflow Eastern Partners, L.P. and A-1 Storage of
Canfield, Ltd.
    
    
    (3
    )10.3
    
    Amendment to Credit Agreement dated February 23, 1996
between Everflow Eastern, Inc. and Everflow Eastern
Partners, L.P. and Bank One, Texas, National Association
    
    
    (5
    )10.4
    
    Second Amendment to Credit Agreement dated December 30,
1996 between Everflow Eastern, Inc. and Everflow Partners,
L.P. and Bank One, Texas, National Association
    
    
    (5
    )10.5
    
    Loan Modification Agreement dated June 16, 1997 between
Bank One, N.A., Bank One, Texas, N.A. and Everflow
Eastern, Inc. and Everflow Eastern Partners, L.P.
    
    
    (6
    )10.6
    
    Loan Modification Agreement dated May 29, 1998 between
Bank One, N.A., Successor to Bank One, Texas, N.A., and
Everflow Eastern, Inc. and Everflow Eastern Partners L.P.
    
    
    (7
    )10.7
    
    Articles of Organization of Everflow Management
Limited, LLC
    
    
    (8
    )
 E-1




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##### Table of Contents



Exhibit Index
 Exhibit No.
    
    Description10.8
    
    Operating Agreement of Everflow Management Limited,
LLC dated March 8, 1999
    
    
    (8
    )10.9
    
    Loan Modification Agreement dated May 25, 1999 between
Bank One, N.A., and Everflow Eastern, Inc. and Everflow
Eastern Partners, L.P.
    
    
    (9
    )10.10
    
    Loan Modification Agreement dated September 19, 2000,
between Bank One, N.A., and Everflow Eastern, Inc.
and Everflow Eastern Partners, L.P.
    
    
    (10
    )10.11
    
    Loan Modification Agreement dated August 28, 2001
between Bank One, N.A., and Everflow Eastern, Inc.
and Everflow Eastern Partners, L.P.
    
    
    (11
    )14.1
    
    Code of Ethics
    
    
    (12
    )21.1
    
    Subsidiaries of the Registrant
    
    
    (4
    )31.1
    
    Certification of CEO Pursuant to Section 302 of the
Sarbanes-Oxley Act of 200231.2
    
    Certification of CFO Pursuant to Section 302 of the
Sarbanes-Oxley Act of 200232.1
    
    Certification Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
 
 (1)
    
    Incorporated herein by reference to the appropriate exhibit to Registrants Registration
Statement on
Form S-1 (Reg. No. 33-36919).(2)
    
    Incorporated herein by reference to the appropriate exhibit to the Registrants Annual Report
on Form 10-K for the year ended December 31, 1994 (File No. 0-19279).(3)
    
    Incorporated herein by reference to the appropriate exhibit to the Registrants Quarterly
Report on Form 10-Q for the third quarter ended September 30, 1995 (File No. 0-19279).(4)
    
    Incorporated herein by reference to the appropriate exhibit to the Registrants Annual Report
on Form 10-K for the year ended December 31, 1995 (File No. 0-19279).(5)
    
    Incorporated herein by reference to the appropriate exhibit to the Registrants Annual Report
on Form 10-K for the year ended December 31, 1996 (File No. 0-19279).(6)
    
    Incorporated herein by reference to the appropriate exhibit to the Registrants Quarterly
Report on Form 10-Q for the second quarter ended June 30, 1997 (File No. 0-19279).(7)
    
    Incorporated herein by reference to the appropriate exhibit to the Registrants Quarterly
Report on Form 10-Q for the second quarter ended June 30, 1998 (File No. 0-19279).(8)
    
    Incorporated herein by reference to the appropriate exhibit to the Registrants Quarterly
Report on Form 10-Q for the first quarter ended March 31, 1999 (File No. 0-19279).(9)
    
    Incorporated herein by reference to the appropriate exhibit to the Registrants Quarterly
Report on Form 10-Q for the second quarter ended June 30, 1999 (File No. 0-19279).(10)
    
    Incorporated herein by reference to the appropriate exhibit to the Registrants Quarterly
Report on Form 10-Q for the third quarter ended September 30, 2000 (File No. 0-19279).(11)
    
    Incorporated herein by reference to the appropriate exhibit to the Registrants Quarterly
Report on Form 10-Q for the third quarter ended September 30, 2001 (File No. 0-19279).(12)
    
    Incorporated herein by reference to the appropriate exhibit to the Registrants Annual Report
on Form 10-K for the year ended December 31, 2003 (File No. 0-19279). E-2