Alliance Resource Partners Annual Report 2004

← All annual reports

FY2004 Annual Report · Alliance Resource Partners

Loading PDF…

Performance. Plus.++

ALLIANCE RESOURCE PARTNERS, L.P. 2004 Annual Report and Form 10-K

Alliance Resource Partners, L.P. is the nation’s only

publicly traded master limited partnership involved in the

production and marketing of coal. We have been a publicly

traded partnership since August 1999 and are listed on the

NASDAQ under the symbol “ARLP”.

Financial Highlights
millions except per unit amounts

Operating Data:
Tons Sold
Tons Produced

Revenues Per Ton Sold(1)
Cost Per Ton Sold (2)

Financial Data:
Revenues
Income From Operations
Net Income

Basic Net Income Per LP Unit (3)
Diluted Net Income Per LP Unit (3)

Total Assets
Total Debt

Net Cash Provided By Operating Activities

(1) See Note (4) on page 32 of 2004 Form 10-K for revenues per ton sold definition.
(2) See Note (5) on page 32 of 2004 Form 10-K for cost per ton sold definition.
(3) The weighted average basic units outstanding for the years ended

December 31, 2004 and 2003, were, 17,940,948 and 17,580,734, respectively,
and on a fully diluted basis, were 18,437,168 and 18,162,839, respectively.

2004

20.8
20.4

29.98
23.64

653.3
78.3
76.6

4.09
3.98

412.8
180.0

145.1

$
$

$
$
$

$
$

2003

19.5
19.2

26.83
20.80

542.7
49.1
47.9

2.71
2.62

336.5
180.0

110.3

$
$

$
$
$

$
$

Alliance Resource Partners, L.P.

Core strengths and investment highlights
• Geographic and product diversity
• Efficient, low-cost operator since 1971
• Consistent track record for growth and market performance
• Long-term relationships with major electric utilities and industrial customers
• Coal marketed from three of the four major U.S. coal producing regions
• Sixth largest coal producer in the eastern U.S.

S
N
O
T
M
M

S
N
O
I
L
L
I
M
N

I
S
R
A
L
L
O
D

TONS OF COAL SOLD
2000 -2004

TONS OF COAL PRODUCED
2000 -2004

REVENUES
2000 -2004

S
N
O
T
M
M

S
N
O
I
L
L
I
M
N

I
S
R
A
L
L
O
D

800

700

600

500

400

300

200

100

2000

2001 2002 2003 2004

2000

2001 2002 2003 2004

2000

2001 2002 2003 2004

NET INCOME(4)
2000 -2004

CASH FLOW FROM OPERATIONS
2000 -2004

EBITDA(5)
2000 -2004

S
N
O
I
L
L
I
M
N

I
S
R
A
L
L
O
D

150

120

S
N
O
I
L
L
I
M
N

I
S
R
A
L
L
O
D

150

120

2000 2001 2002 2003 2004

(4) Net Income for 2001 includes $7.9 million for the cumulative effect of the change in the method of estimating coal workers black lung benefits liability effective January 1, 2001.
(5) See Note (6) on page 32 of 2004 Form 10-K for EBITDA definition, a reconciliation of EBITDA to Net Income and Management’s reason why disclosure of EBITDA is useful to investors.

C
O
M
P
A
N
Y
O
V
E
R
V
I
E
W

2
0
0
4

Alliance Resource Partners, L.P. Coal Mining Complexes

GIBSON COMPLEX
Mining Type: Underground
Mining Method: Continuous mining
Coal Type: Low-sulfur
Transportation: Truck & Barge

PATTIKI COMPLEX
Mining Type: Underground
Mining Method: Continuous mining
Coal Type: High-sulfur
Transportation: CSX & Barge

PONTIKI COMPLEX
Mining Type: Underground
Mining Method: Continuous mining
Coal Type: Low-sulfur
Transportation: NS & Truck

Illinois

Indiana

Ohio

METTIKI COMPLEX
Mining Type: Underground
Mining Method: Longwall
and continuous mining
Coal Type: Medium-sulfur
Transportation: CSX & Truck

Maryland

West Virginia

Kentucky

Virginia

MC MINING COMPLEX
Mining Type: Underground
Mining Method: Continuous mining
Coal Type: Low-sulfur
Transportation: CSX & Truck

DOTIKI COMPLEX
Mining Type: Underground
Mining Method: Continuous mining
Coal Type: High-sulfur
Transportation: CSX, PAL, Truck & Barge

WARRIOR COMPLEX
Mining Type: Underground
Mining Method: Continuous mining
Coal Type: High-sulfur
Transportation: CSX, PAL & Truck

HOPKINS COMPLEX
Mining Type: Surface
Mining Method: Contour, truck and
shovel, and dragline area mining
Coal Type: High-sulfur
Transportation: CSX, PAL & Truck

Elk Creek Mine (Under construction)
Mining Type: Underground
Mining Method: Continuous mining
Coal Type: High-sulfur

4-22.qxd 4/22/05 4:42 PM Page 1

Joseph W. Craft III
President and
Chief Executive Officer

To Our Fellow Unitholders:

Alliance Resource Partners reached an important milestone
in 2004 as we celebrated our fifth anniversary as a publicly
traded partnership. At the time of our initial NASDAQ
listing in August 1999, the coal industry was faced with
a challenging market environment and a perception that
competing fuels – particularly natural gas – were preferable
to coal. Over the last five years, however, natural gas prices
have more than tripled and are currently forecasted to remain
near historically high levels for the foreseeable future. As a
result, the current market environment for coal is strong and
the outlook is bright.

Alliance Resource Partners has effectively capitalized on this
favorable shift in the market. Consider the following results
we achieved during 2004:
• Completed our fourth consecutive year of record profits
• Achieved record results for revenues, net income, EBITDA,
cash flow from operations, production tons and tons sold

• Provided unitholders with a total return of more than

127 percent

• Increased distributions to unitholders 33 percent

over 2003

• Recorded a 115 percent increase in unit price over the

Clean-burning, abundant, low-cost coal is now consid-

prior year.

ered the fuel of choice to meet America’s electricity needs
today and in the future. Current market fundamentals,
including a stronger economy, low utility stockpiles, supply
constraints and environmental compliance initiatives by
power generators, have created significant opportunities for
the coal industry. As evidenced by our performance,

With these results, Alliance Resource Partners is a perform-
ance leader in the master limited partnership sector and
among the most profitable publicly traded coal companies
in America.

Alliance Resource Partners has consistently delivered

sterling performance, plus much more.

4-22.qxd 4/22/05 4:42 PM Page 2

U.S. ELECTRICITY FUEL SOURCES
Electricity Generation by Fuel Source 2004

U.S. COAL DEMAND
Millions of Tons

Coal
50.0%

Natural Gas
17.7%

Nuclear
19.9%

Hydro
6.6%

Other
5.8%

Source: Electric Power Monthly - March 2005

1,600

1,400

1,200

1,000

800

600

400

0
8
9
1

5
8
9
1

0
9
9
1

5
9
9
1

0
0
0
2

5
0
0
2

0
1
0
2

5
1
0
2

0
2
0
2

5
2
0
2

Source: EIA Annual Energy Outlook
2005 Reference Case

Delivery. Plus.+ {CUSTOMERS}

Anticipating our customers’ growing demand for coal, in October 2004 Alliance
Resource Partners acquired 100 million tons of reserves through two separate
coal leases.

SETTING RECORDS

Our 2004 net income increased 60 percent to a record $76.6
million, or $4.09 per basic limited partnership unit, com-
pared with $47.9 million, or $2.71 per unit, in 2003. These
results are consistent with our past performance as Alliance
Resource Partners’ net income has increased at a compounded
annual growth rate of 67 percent since 2001.

Our 2004 revenues totaling $653.3 million also broke
previous records. We achieved this 20 percent increase over
2003 revenues, in part, by increasing production and coal
sales volumes to capitalize on continued improvement in
coal market prices. Our average coal sales price per ton
realized during 2004 jumped $3.02 compared with prices
one year ago.

Alliance Resource Partners’ 2004 EBITDA(5) – or income

before net interest expense, income taxes and depreciation,
depletion and amortization –was $147.9 million, reflecting a
25 percent compounded annual growth rate since 2001.

In recognition of our consistent, strong financial perform-

ance, we were once again listed as one of the nation’s fastest
growing companies in Business Week magazine’s 2004 ranking
of “100 Hot Growth Companies.” The list is compiled from
publicly traded companies with annual sales between $50
million and $1.5 billion and is based on three-year results in

sales growth, earnings growth and return on invested capital.
Alliance Resource Partners jumped to number 26 on the list
in 2004 after debuting at number 83 in 2003.

SHARING PROFITS

Our primary objective is to achieve sustainable, capital-effi-
cient growth in cash flow that will allow us to increase distri-
butions to our unitholders. We have consistently delivered
on this objective by increasing distributions to unitholders
50 percent since 2001. Our performance during 2004 was
especially notable: Alliance Resource Partners increased
quarterly cash distributions for the fourth quarter of 2004
to 75 cents per unit, up more than 33 percent over the
2003 fourth quarter distribution of 56.25 cents per unit.

DELIVERING RESULTS

Robust coal market conditions enabled Alliance Resource
Partners to sell a record 20.8 million tons of coal in 2004,
up 7 percent over 2003. As coal market fundamentals remain
strong, Alliance Resource Partners intends to increase coal
production in 2005 to an estimated 22.2 to 22.5 million tons.
Substantially all of our estimated 2005 production is already
committed under existing coal sales agreements. For 2006, we
are expecting to produce 23.0 to 23.5 million tons of coal.

4-22.qxd 4/22/05 4:42 PM Page 3

Dedication.Plus.+ {EMPLOYEES}

Throughout the year, our employees consistently demonstrated their ability to
successfully respond to opportunities and challenges.

We produce a diverse range of steam coals, satisfying a
broad range of customer specifications. Ongoing efforts to
optimize capacity and improve efficiencies allow Alliance
Resource Partners to take advantage of market opportunities.
The following 2004 operational highlights illustrate how we
have grown to become the sixth largest coal producer in the
eastern United States:
• Invested $54.7 million in capital expenditures to expand
our operating capacity, enhance our efficiency and main-
tain our assets

• Signed agreements with two third-party contract mining
companies to produce coal from reserves that we control
near our Mettiki complex. Deliveries began in July, increas-
ing annual production by approximately 625,000 tons
• Installed additional equipment at our Gibson County,
Dotiki and Pattiki mines to increase their production
capabilities

• Restarted operations at our Newcoal surface mine in

response to requirements from existing customers and
increased demand for Illinois Basin coal.

In 2004, these actions helped Alliance Resource Partners
capitalize on promising growth and profit opportunities.
Additionally, while Alliance Resource Partners’ production
has grown at a 5 percent compounded annual growth

rate since 2001 – based upon our view of the coal markets
and anticipated demand for our product – our goal is to
increase production at an 8 percent to 9 percent annual
rate going forward.

We intend to continue our efforts to maximize operating

capacity and optimize the performance of our assets in
the future. For 2005, we have set a $79.9 million capital
expenditure budget, which includes maintenance capital and
equipment additions. Anticipated expenditures include the
opening of the Elk Creek mine, addition of a fourth continu-
ous mining unit at the Warrior complex, equipment additions
at the Pattiki mine, transitioning the Pontiki mine to the Van
Lear seam reserve and infrastructure improvements at the
Warrior, Gibson County and Mt. Vernon transfer terminal
operations. These strategic investments will allow Alliance
Resource Partners to continue moving forward with speed,
flexibility and innovation.

TESTING METTLE

After more than 33 years of relatively smooth operations,
adversity struck twice during 2004.

On February 11, our Dotiki mine was idled following
a mine fire that originated with a diesel supply trailer. This
underground complex employs approximately 360 workers.

4-22.qxd 4/22/05 4:42 PM Page 4

MARKET PERFORMANCE COMPARISON
Trading History - Dec 01 to Dec 04
Trading data adjusted to reflect dividents or distributions

350

300

250

200

150

100

ARLP

DJIA

S&P 500 NASDAQ

1
0
-
c
e
D

2
0
-
n
a
J

2
0
-
b
e
F

2
0
-
r
a
M

2
0
-
r
p
A

2
0
-
y
a
M

2
0
-
n
u
J

2
0
-
l
u
J

2
0
-
g
u
A

2
0
-
p
e
S

2
0
-
t
c
O

2
0
-
v
o
N

2
0
-
c
e
D

3
0
-
n
a
J

3
0
-
b
e
F

3
0
-
r
a
M

3
0
-
r
p
A

3
0
-
y
a
M

3
0
-
n
u
J

3
0
-
l
u
J

3
0
-
g
u
A

3
0
-
p
e
S

3
0
-
t
c
O

3
0
-
v
o
N

3
0
-
c
e
D

4
0
-
n
a
J

4
0
-
b
e
F

4
0
-
r
a
M

4
0
-
r
p
A

4
0
-
y
a
M

4
0
-
n
u
J

4
0
-
l
u
J

4
0
-
g
u
A

4
0
-
p
e
S

4
0
-
t
c
O

4
0
-
v
o
N

4
0
-
c
e
D

Growth.Plus.+ {UNITHOLDERS}

During 2004, Alliance Resource Partners provided a total return to unitholders of
more than 127 percent.

On December 25, a fire was discovered near the bottom

of the slope at our Excel No. 3 mine which resulted in the
mine being idled the following day. This underground
complex employs approximately 250 workers.

We are grateful that not one injury resulted to anyone

involved in either of these around-the-clock firefighting
and mine recovery efforts. Safety is more than a priority
at Alliance Resource Partners; it is the way we do business.
The extensive safety procedures and training our employees
practice every day save lives and minimize damages.

RECOVERY

We are indebted to our employees, our business partners,
the local communities, the U.S. Mine Safety and Health
Administration (MSHA), and the Kentucky Office of Mine
Safety and Licensing for their unwavering support and assis-
tance in implementing state-of-the art firefighting and mine
recovery plans. As a result of cooperative efforts and team-
work, we achieved mine recovery results never before seen
in the coal mining industry. Both mines reopened safely
and successfully in record time: Dotiki resumed production
only 28 days after the fire occurred, and initial production

resumed at Excel No. 3 less than 60 days after the fire
was discovered.

David Lauriski, former assistant secretary of labor for
MSHA, called the Dotiki recovery “a case-book example of
how cooperation, technology and quick decision-making
can contribute to the speedy recovery of mine fires.” John
Correll, deputy assistant secretary of labor for MSHA,
hailed the recovery of Excel No. 3 as an example of how
“working together toward a common objective, industry and
government…[can safely return] miners to their jobs.” Alliance
Resource Partners is cooperating with MSHA’s Technical
Support Department to refine the mine recovery methods used
at Dotiki and Excel in order to benefit the entire coal industry.

FUELING GROWTH

In October 2004, Alliance Resource Partners announced
the addition of 100 million tons of high-sulfur coal through
leases of the Elk Creek and Tunnel Ridge reserves. These
leases increased our reserve base to more than 512 million
tons and provide us the opportunity to develop two new
large scale mining operations.

4-22.qxd 4/22/05 4:42 PM Page 5

4-22.qxd 4/22/05 4:42 PM Page 6

Results.Plus.+ {WALL STREET}

Alliance Resource Partners is a performance leader in the MLP sector and among
the most profitable publicly traded coal companies in America.

Development of the Elk Creek reserves, located in
Hopkins County, Kentucky, is underway and we expect
initial production to begin by the end of 2005. In January
2005, we completed the lease of the Tunnel Ridge reserves,
which are located in West Virginia and Pennsylvania, and
have begun efforts to permit the property and secure coal
supply agreements. Assuming these efforts are successful, we
currently estimate that initial production at Tunnel Ridge
could begin in the 2008 – 2009 timeframe.

Alliance Resource Partners also recently announced that
we have begun permitting the Gibson County South reserve
area, which is located near our current Gibson County mining
complex in Indiana. Gibson County South contains an esti-
mated 83 million tons of high quality Illinois Basin coal.
Assuming permits can be obtained on a timely basis and
adequate coal supply agreements can be secured, we currently
anticipate bringing this property into production in the
2008 – 2009 timeframe.

All of these projects reflect our commitment to growth
and our focus on the acquisition and development of high-
sulfur coal reserves in the Illinois Basin and Northern
Appalachia producing regions of the U.S.

SEIZING OPPORTUNITY

In response to legislative and regulatory initiatives, electric
utilities have already announced plans to add approximately
30 gigawatts of new scrubbed capacity over the next four
years. As utilities continue to develop their environmental
compliance strategies, some industry experts estimate as
much as 100 gigawatts of new scrubbed capacity could be
operational by 2008.

With the installation of these scrubbers, power genera-
tors will be able to cleanly and efficiently burn higher sulfur
coal. We believe this will result in a substantial swing in
market demand from low sulfur to high sulfur coal. We are
positioning Alliance Resource Partners to take advantage of
what we believe is a significant shift in market opportunity.

LOOKING AHEAD

The outlook for Alliance Resource Partners is positive and
promising. The fundamentals of the coal industry have
never been better. Coal continues to be the fuel of choice
for baseload electricity generation – more than 50 percent
of America’s electricity is fueled by coal – and demand for

4-22.qxd 4/22/05 4:42 PM Page 7

4-22.qxd 4/22/05 4:42 PM Page 8

ability to successfully respond to opportunities and chal-
lenges. Through their efforts, Alliance Resource Partners
once again delivered superior results, plus much more. I
applaud their determination, dedication, teamwork,
integrity and commitment to excellence.

Joseph W. Craft III
President and
Chief Executive Officer

April 21, 2005

electricity is growing. Domestic coal is dependable, it’s
reliable, it’s abundant and it’s being burned cleaner every
day. Competing fuels – natural gas and oil – are trading
near all-time high prices. In addition, international demand
for coal is strong as global economies, particularly China
and India, continue to experience significant growth and
increased demand for energy.

Alliance Resource Partners has built a strong track
record and we are focused on future growth in earnings
and distributions. Our business is strong and I believe we are
well positioned to continue our trend of record-setting results.

SALUTING HEROES

In closing, I especially want to thank the more than 2,000
American heroes of Alliance Resource Partners. Throughout
the past year, our employees consistently demonstrated their

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_______________

FORM 10-K

[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

[ ] 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.: 0-26823
_______________

ALLIANCE RESOURCE PARTNERS, L.P.

(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

DELAWARE
(STATE OR OTHER JURISDICTION OF
INCORPORATION OR ORGANIZATION)

73-1564280
(IRS EMPLOYER IDENTIFICATION NO.)

1717 SOUTH BOULDER AVENUE, SUITE 600, TULSA, OKLAHOMA 74119
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES AND ZIP CODE)

(918) 295-7600
(REGISTRANT’S TELEPHONE NUMBER, INCLUDING AREA CODE)

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: common units representing limited partner interests

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the

Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and

will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).

Yes [X]

No [ ]

The aggregate value of the common units held by non-affiliates of the registrant (treating all executive officers and

directors of the registrant, for this purpose, as if they may be affiliates of the registrant) was approximately $465,898,654 as of
June 30, 2004, the last business day of the registrant’s most recently completed second fiscal quarter, based on $46.66 per unit,
the closing price of the common units as reported on the Nasdaq National Market on such date.

As of March 15, 2005, 18,130,440 common units were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None

ITEM 1.

ITEM 2.

ITEM 3.

ITEM 4.

ITEM 5.

ITEM 6.

ITEM 7.

TABLE OF CONTENTS

PART I
Business

Properties

Legal Proceedings

Submission of Matters to a Vote of Securities Holders

PART II
Market for Registrant’s Common Units, Related Unitholder Matters and
Issuer Purchases of Equity Securities

Selected Financial Data

Management’s Discussion and Analysis of Financial Condition and Results of Operations

ITEM 7A.

Quantitative and Qualitative Disclosures About Market Risk

ITEM 8.

ITEM 9.

Financial Statements and Supplementary Data

Changes in and Disagreements with Accountant on Accounting and Financial Disclosure

ITEM 9A.

Controls and Procedures

ITEM 9B.

Other

PART III
Directors, Executive Officers, Promoters and Control Persons of the Managing General Partner

ITEM 10.

ITEM 11.

Executive Compensation

ITEM 12.

Security Ownership of Certain Beneficial Owners and Management

ITEM 13.

Certain Relationships and Related Transactions

ITEM 14.

Principal Accountant Fees and Services

PART IV
Exhibits, Financial Statement Schedules

ITEM 15.

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements. These statements are based on our beliefs as well as assump-
tions made by, and information currently available to, us. When used in this document, the words “anticipate,” “believe,” “continue,” “esti-
mate,” “expect,” “forecast”, “may,” “project”, “will,” and similar expressions identify forward-looking statements. These statements
reflect our current views with respect to future events and are subject to various risks, uncertainties and assumptions. Specific factors
which could cause actual results to differ from those in the forward-looking statements include:

•
•
•

•
•
•
•

•
•

•
•
•
•
•
•
•

competition in coal markets and our ability to respond to the competition;
fluctuation in coal prices, which could adversely affect our operating results and cash flows;
deregulation of the electric utility industry or the effects of any adverse change in the domestic coal industry, electric utility
industry, or general economic conditions;
dependence on significant customer contracts, including renewing customer contracts upon expiration of existing contracts;
customer bankruptcies and/or cancellations of, or breaches to existing contracts;
customer delays or defaults in making payments;
fluctuations in coal demand, prices and availability due to labor and transportation costs and disruptions, equipment
availability, governmental regulations and other factors;
our productivity levels and margins that we earn on our coal sales;
any unanticipated increases in labor costs, adverse changes in work rules, or unexpected cash payments associated with
post-mine reclamation and workers’ compensation claims;
any unanticipated increases in transportation costs and risk of transportation delays or interruptions;
greater than expected environmental regulation, costs and liabilities;
a variety of operational, geologic, permitting, labor and weather-related factors;
risk of major mine-related accidents, such as mine fires, or interruptions;
results of litigation;
difficulty maintaining our surety bonds for mine reclamation as well as workers’ compensation and black lung benefits; and
difficulty obtaining commercial property insurance, and risks associated with our current 10.0% participation (excluding any
applicable deductible) in our commercial insurance property program.

If one or more of these or other risks or uncertainties materialize, or should underlying assumptions prove incorrect, our actual results
may differ materially from those described in any forward-looking statement. When considering forward-looking statements, you should
also keep in mind the risk factors described in “Risk Factors” below. The risk factors could also cause our actual results to differ materially
from those contained in any forward-looking statement. We disclaim any obligation to update the above list or to announce publicly the
result of any revisions to any of the forward-looking statements to reflect future events or developments.

You should consider the information above when reading any forward-looking statements contained:

in this Annual Report on Form 10-K;
other reports filed by us with the SEC;
our press releases; and

•
•
•
• written or oral statements made by us or any of our officers or other authorized persons acting on our behalf.

ITEM 1. BUSINESS

General

PART I

We are a diversified producer and marketer of coal to major United States utilities and industrial users. We began mining operations
in 1971 and, since then, have grown through acquisitions and internal development to become what we believe to be the sixth largest coal
producer in the eastern United States. At December 31, 2004, we had approximately 442.4 million tons of reserves in Illinois, Indiana,
Kentucky, Maryland and West Virginia. In 2004, we produced 20.4 million tons of coal and sold 20.8 million tons of coal. The coal we
produced in 2004 was 32.3% low-sulfur coal, 15.7% medium-sulfur coal and 52.0% high-sulfur coal. In 2004, approximately 88% of our
medium- and high-sulfur coal was sold to utility plants with installed pollution control devices, also known as “scrubbers,” to remove
sulfur dioxide. We classify low-sulfur coal as coal with a sulfur content of less than 1%, medium-sulfur coal as coal with a sulfur content
between 1% and 2%, and high-sulfur coal as coal with a sulfur content of greater than 2%.

At December 31, 2004, we operated seven underground mining complexes and one surface operation in Illinois, Indiana, Kentucky and
Maryland. Our mining activities are organized into three operating regions: (a) the Illinois Basin operations, (b) the East Kentucky opera-
tions, and (c) the Maryland operations. At our Warrior Complex, we host and operate a coal synfuel facility, supply the facility with coal
feedstock, assist with the marketing of coal synfuel and provide other services to the owner of the synfuel facility. In January 2005, we
entered into several agreements to provide similar services for a synfuel facility to be located at our Gibson Complex and entered into three
short-term agreements to provide coal feedstock to a synfuel facility located at the power plant of the Mettiki Complex’s primary customer.
We have no reportable segments because our operations solely consist of producing and marketing coal and providing rental and service
fees associated with producing and marketing coal synfuel.

We and our subsidiary, Alliance Resource Operating Partners, L.P. (the intermediate partnership), are Delaware limited partnerships
formed to acquire, own and operate certain coal production and marketing assets of Alliance Resource Holdings, Inc. (Alliance Resource
Holdings), a Delaware corporation formerly known as Alliance Coal Corporation. We completed our initial public offering in August 1999, at
which time Alliance Resource Holdings contributed certain assets in exchange for cash, common and subordinated units, general partner
interests, the right to receive incentive distributions as defined in the partnership agreement and the assumption of related indebtedness.
Our managing general partner, Alliance Resource Management GP, LLC, and our special general partner, Alliance Resource GP, LLC
(collectively referred to as our general partners), own an aggregate 2% general partner interest in us. Our limited partners, including the
general partners as holders of common units, own an aggregate 98% limited partner interest in us.

Our internet address is www.arlp.com, and we make available on our internet website our Annual Reports on Form 10-K, our Quarterly
Reports on Form 10-Q, our Current Reports on Form 8-K and Form 4s for our Section 16 filers (and amendments and exhibits, such as press
releases, to such filings) as soon as reasonably practicable after we electronically file with or furnish such material to the Securities and
Exchange Commis-sion. Our “Code of Ethics” for our chief executive officer and our senior financial officers is also posted on our website.

Recent Development

MC Mining Mine Fire. On December 26, 2004 the MC Mining Excel No. 3 mine was temporarily idled following the occurrence of a mine
fire (the MC Mining Fire Incident). The fire was discovered by mine personnel near the bottom of the Excel No. 3 mine slope late in the
evening of December 25, 2004.

permanent barriers was completed, MC Mining began efforts to repair and rehabilitate the Excel No. 3 mine infrastructure. On February
21, 2005, the repair and rehabilitation efforts had progressed sufficiently to allow initial resumption of production. We anticipate that MC
Mining may return to full production by the end of the first quarter of 2005, but we cannot assure that our ability to produce will not
continue to be adversely impacted by the MC Mining Fire Incident for a period of time.

We maintain commercial property (including business interruption) insurance policies, which provide for self-retention and various
applicable deductibles, including certain monetary and/or time element forms of deductibles and 10% co-insurance, but we cannot give
any assurances as to the eventual timing or amount of any recovery of proceeds under these policies. Please see “Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations; Summary” for a description of the preliminary cost estimates
and the financial impact on our 2004 results.

2004 Events

Elk Creek and Tunnel Ridge. On October 21, 2004, we announced an agreement, subject to finalization of definitive agreements, to enter
into two separate coal leases, which cumulatively will increase our coal reserve holdings by 25%. The Elk Creek reserves (Elk Creek) are
located in Hopkins County, Kentucky, and the Tunnel Ridge reserves (Tunnel Ridge) are located in Ohio County, West Virginia and
Washington County, Pennsylvania. These leases are estimated to contain approximately 100 million tons of high-sulfur coal reserves. The
lessor for both leases is our special general partner. We also announced plans to immediately begin the development process for these
properties, which includes obtaining the necessary mining permits and securing sufficient coal sales commitments to justify the capital
investment needed to bring these properties into production.

The Elk Creek reserve area encompasses approximately 9,000 acres and is contiguous to our Hopkins County Coal complex. The Elk
Creek coal reserves are currently estimated to include approximately 30 million tons of high-sulfur coal. The Elk Creek mine will be an
underground mining complex that mines the West Kentucky No. 9 and No. 11 coal seams. We will use continuous mining units, and employ
room-and-pillar mining techniques. We intend to use the existing coal handling and other surface facilities owned by Hopkins County Coal.
We anticipate the Elk Creek complex will employ as many as 250 individuals and produce up to 3.2 million tons of coal annually. We
estimate total capital expenditures to develop Elk Creek to be approximately $65.0 million. In December, 2004, the board of directors of our
managing general partner approved the capital expenditures associated with Elk Creek. Coal supply commitments are currently being
pursued. Construction of the Elk Creek mining complex began in the first quarter of 2005. We expect to fund these capital expenditures
with available cash and marketable securities on hand, future cash generated from operations and/or borrowings available under our
revolving credit facility.

In December 2000, Hopkins County Coal entered into an option agreement to lease and/or sublease the Elk Creek reserves from our
special general partner. Under the terms of the option to lease and sublease, Hopkins County Coal paid an option fee of $645,000 during
the year ended December 31, 2000, and paid option fees of $684,000 during each of the years ended December 31, 2001, 2002 and 2004.
The 2003 option fee of $684,000 was paid in January 2004. Upon exercise of the option to lease or sublease, Hopkins County Coal is obli-
gated to make an additional five annual advance minimum royalty payments of $684,000 per year, which royalty is fully recoupable against
earned royalties. The earned royalty rate under the lease and/or sublease is $0.25 per ton.

In January 2005, we acquired 100% of the limited liability company member interests of Tunnel Ridge, LLC for approximately $500,000
and the assumption of reclamation liabilities from Alliance Resource Holdings, Inc., a company owned by our management. Tunnel Ridge,
LLC controls through a coal lease agreement with the special general partner an estimated 70 million tons of high-sulfur coal in the
Pittsburgh No. 8 coal seam. The Tunnel Ridge reserve area encompasses approximately 50,571 acres of land located in Ohio County, West
Virginia and Washington County, Pennsylvania. Under the terms of the coal lease, beginning on January 1, 2005, Tunnel Ridge, LLC began
paying our special general partner an advance minimum royalty of $3.0 million per year, which advance royalty payments will be fully
recoupable against earned royalties. The earned royalty rate under the coal lease is the greater of $0.75 per ton or 3.0% of the per ton
gross sales price f.o.b. barge. The term of the coal lease is the earlier of 30 years or until exhaustion of all mineable and merchantable
coal. We have termination rights after the initial four years of the coal lease.

Tunnel Ridge, LLC also controls, under a separate lease agreement with our special general partner, the rights to approximately 900
acres of surface land and other tangible assets. Under the terms of the lease agreement, Tunnel Ridge, LLC shall pay our special general
partner an annual lease payment of $240,000 beginning January 1, 2005. The lease agreement has an initial term of four years, which term
may be extended by Tunnel Ridge, LLC, at the same annual lease payment rate, to be consistent with the term of the coal lease.

We have initiated the permitting process for the Tunnel Ridge reserve area.We anticipate the Tunnel Ridge operation will use a long-
wall miner for the majority of its coal extraction as well as continuous mining units for preparation of the mine for future longwall mining.
We estimate the Tunnel Ridge operation will be designed to produce up to six million tons of coal annually. We believe production from
Tunnel Ridge may begin as early as 2008. We anticipate the Tunnel Ridge complex will employ as many as 300 individuals. We estimate
total capital expenditures required to develop Tunnel Ridge to be approximately $200 million over a five-year period. We currently expect
to fund these capital expenditures with available cash and marketable securities, future cash generated from operations and/or borrow-
ings available under our revolving credit facility. Definitive development commitment for Tunnel Ridge is dependent upon final approval by
the board of directors of our managing general partner.

The Elk Creek and Tunnel Ridge transactions described above are related-party transactions and, as such, were reviewed by the board
of directors of our managing general partner and its conflicts committee. Based upon these reviews, it was determined that these trans-
actions reflect market-clearing terms and conditions customary in the coal industry. As a result, the board of directors of our managing
general partner and its conflicts committee approved the Elk Creek and Tunnel Ridge transactions as fair and reasonable to us.

Conversion of Subordinated Units. As of September 30, 2004, we satisfied the final conversion financial tests for converting the remain-
ing subordinated units into common units as provided for under applicable provisions in the Partnership Agreement. On October 21, 2004,
our board of directors of our managing general partner and its conflicts committee approved management’s determination that such final
conversion financial tests were satisfied as of September 30, 2004. As a result, the remaining outstanding subordinated units (i.e.,
3,211,266 subordinated units) held by our special general partner were converted into common units on November 2, 2004.

Dotiki Fire Incident. On February 11, 2004, Webster County Coal, LLC’s (Webster County Coal) Dotiki mine was temporarily idled for a
period of twenty-seven calendar days following the occurrence of a mine fire that originated with a diesel supply tractor (the Dotiki Fire
Incident). As a result of the firefighting efforts of the Mine Safety and Health Administration, Kentucky Department of Mines and Minerals,
and Webster County Coal personnel, Dotiki successfully extinguished the fire and totally isolated the affected area of the mine behind
permanent barriers. Initial production resumed on March 8, 2004. For the Dotiki Fire Incident, we had commercial property insurance that
provided coverage for damage to property destroyed, interruption of business operations, including profit recovery, and expenditures
incurred to minimize the period and total cost of disruption to operations. Please see “Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations; Summary” for a description of the accounting treatment of expenses and insurance proceeds
associated with the Dotiki Fire Incident.

Mining Operations

We produce a diverse range of steam coals with varying sulfur and heat contents, which enables us to satisfy the broad range of

specifications required by our customers. The following chart summarizes our coal production by region for the last five years.

Operating Regions and Complexes

2004

2003

2002

2001

2000

(tons in millions)

Illinois Basin Operations:

Dotiki, Warrior, Pattiki, Hopkins,
Gibson Complexes
East Kentucky Operations:

Pontiki, MC Mining Complexes

Maryland Operations:
Mettiki Complex

Total

13.6

3.6

3.2
20.4

12.3

3.6

3.3
19.2

12.1

3.0

2.9
18.0

11.9

2.8

2.7
17.4

8.4

2.7

2.6
13.7

Illinois Basin Operations. Our Illinois Basin mining operations are located in western Kentucky, southern Illinois and southern Indiana.
We have approximately 1,200 employees in the Illinois Basin and currently operate five mining complexes. Additionally, we host a coal syn-
fuel facility at one of our mining complexes.

Dotiki Complex. Webster County Coal, LLC operates Dotiki, which is an underground mining complex located near the city of
Providence in Webster County, Kentucky. The complex was opened in 1966, and we purchased the mine in 1971. Our Dotiki complex
utilizes continuous mining units employing room-and-pillar mining techniques. In 2004, Dotiki increased mining capacity with the addition
of two continuous miners. Also in 2004, the preparation plant throughput capacity was increased by 30% from 1,000 tons of raw coal to
1,300 tons of raw coal an hour. Capacity was increased principally to accommodate a change in customer requirements for washed coal
rather than raw coal.

On February 11, 2004, the Dotiki mine was temporarily idled following the occurrence of a mine fire. The fire was successfully
extinguished and the affected area of the mine was totally isolated behind permanent barriers. Production resumed on March 8, 2004. For
information on the fire at our Dotiki mine, please see “2004 Events – Dotiki Fire Incident” above.

Production of high-sulfur coal from the complex is shipped via the CSX and PAL railroads and by truck on U.S. and state highways. Our
primary customers for coal produced at Dotiki are Louisville Gas & Electric (LG&E), Seminole Electric Cooperative, Inc. (Seminole) and
Tennessee Valley Authority (TVA), all of which purchase our coal pursuant to long-term contracts for use in their scrubbed generating units.

Warrior Complex. Warrior Coal, LLC operates the Cardinal mine, an underground mining complex located near Madisonville, in
Hopkins County, Kentucky, between and adjacent to our other western Kentucky operations. The Warrior complex was opened in 1985 and
acquired by us in February 2003. Warrior utilizes continuous mining units employing room-and-pillar mining techniques producing high-
sulfur coal. Warrior’s preparation plant has a throughput capacity of 600 tons of raw coal an hour.

Warrior sells substantially all of its production to Synfuel Solutions Operating, LLC (SSO) for feedstock in the production of coal syn-
fuel, as discussed below. SSO’s coal synfuel production facility was moved from Hopkins County Coal, LLC (Hopkins) to Warrior in April
2003. Warrior’s production can be shipped via the CSX and PAL railroads and by truck on U.S. and state highways. Additionally, Warrior
purchased supplemental production from Dotiki and a third-party supplier for resale to SSO and will continue to purchase tons from the
third-party supplier through June 2007. SSO continues to ship coal synfuel to electric utilities that have been purchasers of our coal. We
maintain “back-up” coal supply agreements with these long-term customers for our coal, which automatically provide for the sale of our
coal to them in the event they do not purchase coal synfuel from SSO.

We have entered into long-term agreements with SSO to host and operate its coal synfuel facility currently located at Warrior,
supply the facility with coal feedstock, assist SSO with the marketing of coal synfuel and provide other services. These agreements expire
on December 31, 2007 and provide us with coal sales, rental and service fees from SSO based on the synfuel facility throughput tonnages.
These amounts are dependent on the ability of SSO’s members to use certain qualifying tax credits applicable to the facility. As discussed
above, we sell most of the coal produced at Warrior to SSO, while Alliance Coal Sales, a division of Alliance Coal, assists SSO with the
sale of its coal synfuel to our customers pursuant to a sales agency agreement. The term of each of these agreements is subject to early
cancellation provisions customary for transactions of these types, including the unavailability of synfuel tax credits, the termination of
associated coal synfuel sales contracts, and the occurrence of certain force majeure events. Therefore, the continuation of the revenues
associated with the coal synfuel production facility cannot be assured. However, we have maintained “back up” coal supply agreements
with each coal synfuel customer that automatically provide for sale of our coal to these customers in the event they do not purchase coal
synfuel from SSO. In conjunction with a decision to relocate the coal synfuel production facility to Warrior, agreements for providing cer-
tain of these services were assigned to Alliance Service, Inc. (Alliance Service), a wholly-owed subsidiary of Alliance Coal, in December
2002. Alliance Service is subject to federal and state income taxes.

For 2004, the incremental annual net income benefit from the combination of the various coal synfuel-related agreements
associated with the facility located at Warrior was approximately $16.9 million, assuming that coal pricing would not have increased with-
out the availability of synfuel. The continuation of the incremental net income benefit associated with SSO’s coal synfuel facility cannot
be assured. We earn income by supplying SSO’s synfuel facility with coal feedstock, assisting SSO with the marketing of coal synfuel, and
providing rental and other services. Pursuant to our agreement with SSO, we are not obligated to make retroactive adjustments or reim-
bursements if SSO’s tax credits are disallowed.

In June 2003, the Internal Revenue Service (IRS) suspended the issuance of private letter rulings on the significant chemical change
requirement to qualify for synfuel tax credits and announced that it was reviewing the test procedures and results used by taxpayers to
establish that a significant chemical change had occurred. In October 2003, the IRS completed its review and concluded that the test
procedures and results were scientifically valid if applied in a consistent and unbiased manner. The IRS has resumed issuing private letter
rulings under its existing guidelines. SSO has advised us that its private letter ruling could be reviewed by the IRS as part of a tax audit,
similar to the IRS reviews of other synfuel procedures. SSO has also advised us that the Permanent Subcommittee on Investigations of the
Senate Committee on Governmental Affairs (Subcommittee) is reviewing the synfuel industry, that the Subcommittee has indicated that
they hope to interview almost all taxpayers that are involved in the synfuel business and that SSO has been requested to meet informally
with the Subcommittee to help enhance the Subcommittee’s knowledge of the synfuel industry.

Pattiki Complex. White County Coal, LLC operates Pattiki, which is an underground mining complex located near the city of Carmi,
in White County, Illinois. We began construction of the complex in 1980 and have operated it since its inception. Our Pattiki complex
utilizes continuous mining units employing room-and-pillar mining techniques. During 2004, Pattiki increased mining capacity with the addi-
tion of one continuous miner. The preparation plant has a throughput capacity of 1,000 tons of raw coal an hour.

Production of high-sulfur coal from the complex is shipped via the CSX railroad. Our primary customers for coal produced at Pattiki
are Ameren Energy Fuels & Services Company, Northern Indiana Public Service Company (NIPSCO) and Seminole for use in their generat-
ing units. NIPSCO and Seminole have scrubbed generating units.

Hopkins Complex. Hopkins County Coal, LLC operates a mining complex consisting of one active surface mine, one undeveloped sur-
face mine, and the Elk Creek reserves that are being prepared for development in 2005. Hopkins County Coal is located near the city of
Madisonville in Hopkins County, Kentucky. We acquired the complex in January 1998. The active surface mine was idled in June 2003
because we were unable to secure sufficient sales commitments in the Illinois Basin region. In October 2004, the surface mine was re-
opened in response to incremental sale opportunities from existing customers as well as strong market demand for Illinois Basin region
coal. We anticipate the active surface mine will deplete its coal reserves at the end of 2005.

The surface operation utilizes dragline mining and the preparation plant has a throughput capacity of 1,000 tons of raw coal an hour.

Historically, Hopkins’ production has the ability to be shipped via the CSX and PAL railroads and by truck on U.S. and state highways.

On October 21, 2004, we announced our intent to exercise an option to lease the Elk Creek reserves located in Hopkins County,
Kentucky. The Elk Creek coal reserves consist of approximately 30 million tons of high-sulfur coal. The Elk Creek mine will be an under-
ground mining complex, using continuous mining units employing room-and-pillar mining techniques. We intend to utilize the existing coal
handling and other surface facilities at Hopkins to process and ship the Elk Creek coal. Construction of the Elk Creek complex commenced
in the first quarter of 2005 with estimated capital expenditures of $65 million of which approximately $13.5 million is anticipated to be
incurred in 2005. Initial production is expected to begin in early 2006 with anticipated annual production of 3.2 million tons. For more infor-
mation, please see “2004 Events” above.

Gibson Complex. Gibson County Coal, LLC operates Gibson, an underground mining complex located near the city of Princeton in
Gibson County, Indiana. The mine began production in November 2000. Our Gibson complex utilizes continuous mining units employing
room-and-pillar mining techniques. In 2004, Gibson increased mining capacity with the addition of one continuous mining unit. The prepa-
ration plant has a throughput capacity of 700 tons of raw coal an hour. We refer to the reserves mined at this location as the Gibson “North”
reserves. We also control undeveloped reserves in Gibson County, which are not contiguous to the reserves currently being mined. We refer
to these as the Gibson “South” reserves.

Production from Gibson is a low-sulfur coal, that historically has been primarily shipped via truck approximately 10 miles on U.S. and
state highways to Gibson’s principal customer, PSI Energy Inc. (PSI), a subsidiary of Cinergy Corporation. Gibson’s production is also trucked
to our Mt. Vernon transloading facility for sale to utilities capable of receiving barge deliveries.

In January 2005, Gibson entered into long-term agreements with PC Indiana Synthetic Fuel #2, L.L.C. (PCIN) to host its coal synfuel
facility, supply the facility with coal feedstock, assist PCIN with the marketing of coal synfuel and provide other services. The synfuel
facility is expected to commence operations at Gibson in May 2005. At that time, we expect that the majority of Gibson’s production will
be sold to PCIN. The agreements expire on December 31, 2007 and provide us with coal sales, rental and service fees from PCIN based on
the synfuel facility throughput tonnages. These amounts are dependent on the ability of PCIN’s members to use certain qualifying tax

credits applicable to the facility. The term of each of these agreements is subject to early cancellation provisions customary for transac-
tions of these types, including the unavailability of synfuel tax credits, the termination of associated coal synfuel sales contracts, and the
occurrence of certain force majeure events. Therefore, revenues associated with the coal synfuel production facility cannot be assured.
However, we have entered into “back up” coal supply agreements with each coal synfuel customer that automatically provide for sale of
our coal to these customers in the event they do not purchase coal synfuel from PCIN.

For 2005, the incremental annual net income benefit from the combination of the various coal synfuel related agreements associated
with the facility being relocated to Gibson is estimated to be $3.3 million, assuming that coal pricing would not increase without the avail-
ability of synfuel. This estimated incremental net income cannot be assured. Pursuant to our agreement with PCIN, we are not obligated
to make retroactive adjustments or reimbursements if PCIN’s tax credits are disallowed.

We have initiated the permitting process for the Gibson South reserves and are actively evaluating its development. Capital expen-
ditures required to develop the Gibson South reserves are estimated to be approximately $80 million. Assuming sufficient sales commit-
ments are obtained and the permitting process progresses as anticipated, initial production could commence in the 2008 to 2009 time
frame, with anticipated annual production of 3.2 million tons. Definitive development commitment for Gibson South is dependent upon final
approval by the board of directors of our managing general partner.

East Kentucky Operations. Our East Kentucky mining operations are located in the Central Appalachia coal fields. Our East Kentucky
mines produce low-sulfur coal. We have approximately 500 employees and operate two mining complexes in East Kentucky.

Pontiki Complex. Pontiki Coal, LLC owns Pontiki, an underground mining complex located near the city of Inez in Martin County,
Kentucky. We constructed the mine in 1977. Pontiki owns the mining complex and leases the reserves, and Excel Mining, LLC (Excel), an
affiliate of Pontiki, is responsible for conducting all mining operations. Substantially all of the coal produced at Pontiki in 2004 met or
exceeded the compliance requirements of Phase II of the Clean Air Act amendments. Our Pontiki operation utilizes continuous mining units
employing room-and-pillar mining techniques. The preparation plant has a throughput capacity of 800 tons of raw coal an hour. In February
2005 construction efforts began that will allow Pontiki to migrate its mining units into a new coal seam. The first mining unit is expected
to move into the new coal seam during the third quarter of 2005. Beginning in 2006, production will still be low sulfur, but may no longer
meet the compliance requirements of Phase II Clean Air Act.

Our primary customer for the low-sulfur coal produced at Pontiki is ICG, LLC, the successor-in-interest of certain assets of Horizon
Natural Resources Company. We are in a contract dispute in which ICG is alleging we failed to deliver 138,111 tons of coal. Please read
“Item 13. Legal Proceedings” and “Item 8. Financial Statements and Supplementary Data – Note 17. Commitments and Contingencies.”
Production from the mine is shipped primarily to electric utilities located in the southeastern United States via the Norfolk Southern rail-
road or by truck via U.S. and state highways to various docks on the Big Sandy River in Kentucky.

MC Mining Complex. MC Mining, LLC owns MC Mining, an underground mining complex located near the city of Pikeville in Pike
County, Kentucky. We acquired the mine in 1989. MC Mining owns the mining complex and leases the reserves, and Excel, an affiliate
of MC Mining, is responsible for conducting all mining operations. Substantially all of the coal produced at MC Mining in 2004 met or
exceeded the compliance requirements of Phase II of the Clean Air Act amendments. The complex utilizes continuous mining units employ-
ing room-and-pillar mining techniques. The preparation plant has a throughput capacity of 800 tons of raw coal an hour.

Production from the mine is shipped via the CSX railroad or by truck via U.S. and state highways to various docks on the Big Sandy

River. MC Mining sells its low-sulfur production primarily in the spot market.

On December 26, 2004, MC Mining was temporarily idled following the occurrence of a mine fire. For more information about the MC

Mining Fire Incident, please see “Recent Development – MC Mining Mine Fire” above.

Maryland Operations. Our Maryland mining operation is located in the Northern Appalachia coal fields. We have approximately 220
employees and operate one mining complex in Maryland.

Mettiki Complex. Mettiki Coal, LLC operates Mettiki, an underground longwall mining complex located near the city of Oakland in
Garrett County, Maryland. We constructed Mettiki in 1977 and have operated it since its inception. The operation utilizes a longwall miner
for the majority of the coal extraction as well as continuous mining units used to prepare the mine for future longwall mining. The

pre-paration plant has a throughput capacity of 1,350 tons of raw coal an hour. In response to strong market demand, Mettiki’s production
capacity was increased through two small-scale third party mining operations.

Historically, our primary customer for the medium-sulfur coal produced at Mettiki has been Virginia Electric and Power Company
(VEPCO), which purchased the coal pursuant to a long-term contract for use in the scrubbed generating units at its Mt. Storm, West Virginia
power plant, located less than 20 miles away. Our coal is trucked to Mt. Storm over a private haul road, which links to a state highway.
Mettiki is also served by the CSX railroad.

In January 2005, Mettiki entered into what may be the first of a series of short-term purchase orders with Mt. Storm Coal Supply, LLC
(Mt. Storm Coal Supply) to supply its coal synfuel facility, located at the Mt. Storm power plant, with coal feedstock. Going forward, the
short-term coal feedstock purchase orders are expected to have a term of three months. The incremental quarterly net income benefit from
the coal feedstock agreements is estimated to be $0.4 million. The continuation of the short-term agreements cannot be assured. We have
entered into a “back up” coal supply agreement with VEPCO for sale of our coal in the event VEPCO does not purchase coal synfuel from
Mt. Storm Coal Supply. Pursuant to our agreement with Mt. Storm Coal Supply, we are not obligated to make retroactive adjustments or
reimbursements if Mt. Storm Coal Supply’s tax credits are disallowed.

Mettiki Coal (WV). Mettiki Coal (WV), LLC has a proposed underground mine to be located primarily in Tucker County, West Virginia,
which will eventually replace Mettiki Coal’s existing long-wall mine located in Garret County, Maryland. The proposed mine, which will be
either a long-wall or continuous mining operation, is approximately 10 miles from Mettiki Coal with coal reserves of approximately 23.3
million tons. Total development capital expenditures are estimated to be $29.9 million, of which $4.9 million has been approved, with the
balance subject to approval by the board of directors of our managing general partner. Please see “Regulation and Laws; Mining Permits
and Approvals” below concerning the status of Mettiki Coal (WV) permit application for this new mine.

Other Operations

Mt. Vernon Transfer Terminal, LLC . The Mt. Vernon transfer terminal is a coal loading terminal on the Ohio River at Mt. Vernon, Indiana.
Coal is delivered to Mt. Vernon by both rail and truck. The terminal has a capacity of 8 million tons per year with existing ground storage.
During 2004, the terminal loaded approximately 1.8 million tons for Pattiki, Dotiki, and Gibson customers and for third-party shippers.

Coal Brokerage. As markets allow, we buy coal from outside producers principally throughout the eastern United States, which we then
resell, both directly and indirectly, primarily to utility customers.We purchased and sold approximately 21,000 tons of outside coal from
non-affiliates in 2004. We have a policy of matching our outside coal purchases and sales to minimize market risks associated with buy-
ing and reselling coal. Purchased coal that is delivered to our operations and commingled with our production is not classified as broker-
age coal.

Additional Services. We develop and market additional services in order to establish ourselves as the supplier of choice for our cus-
tomers. Examples of the kind of services we have offered to date include ash and scrubber sludge removal, coal yard maintenance and
arranging alternate transportation services. Revenues from these services represented less than one percent of our total revenues.

Coal Marketing and Sales

As is customary in the coal industry, we have entered into long-term contracts with many of our customers. These arrangements are
mutually beneficial by contributing to both our customers’ and our stability and profitability by providing greater predictability of sales vol-
umes and sales prices. In 2004, approximately 92% and 85% of our sales tonnage and total coal sales, respectively, were sold under long-
term contracts (contracts having a term of greater than one year) with maturities ranging from 2004 to 2023. Our total nominal commit-
ment under significant long-term contracts was approximately 98.6 million tons at December 31, 2004, and is expected to be delivered as
follows: 21.9 million tons in 2005, 20.6 million tons in 2006, 13.0 million tons in 2007, 7.0 million tons in 2008, 6.9 million tons in 2009,
and 29.2 million tons thereafter during the remaining terms of the relevant coal supply agreements. The total commitment of coal under

contract is an approximate number because, in some instances, our contracts contain provisions that could cause the nominal total
commitment to increase or decrease by as much as 20%. The contractual time commitments for customers to nominate future purchase
volumes under these contracts are sufficient to allow us to balance our sales commitments with prospective production capacity. In addi-
tion, the nominal total commitment can otherwise change because of price reopener provisions contained in certain of these long-term
contracts.

The terms of long-term contracts are the results of both bidding procedures and extensive negotiations with each customer. As a
result, the terms of these contracts vary significantly in many respects, including, among others, price adjustment features, price and
contract reopener terms, permitted sources of supply, force majeure provisions, coal qualities, and quantities. Virtually all of our long-term
contracts are subject to price adjustment provisions, which permit an increase or decrease periodically in the contract price to reflect
changes in specified price indices or items such as taxes, royalties or actual production costs. These provisions, however, may not assure
that the contract price will reflect every change in production or other costs. Failure of the parties to agree on a price pursuant to an adjust-
ment or a reopener provision can lead to early termination of a contract. Some of the long-term contracts also permit the contract to be
reopened to renegotiate terms and conditions other than the pricing terms, and where a mutually acceptable agreement on terms and
conditions cannot be concluded, either party may have the option to terminate the contract. The long-term contracts typically stipulate
procedures for quality control, sampling and weighing. Most contain provisions requiring us to deliver coal within stated ranges for
specific coal characteristics such as heat, sulfur, ash, moisture, grindability, volatility and other qualities. Failure to meet these specifica-
tions can result in economic penalties or termination of the contracts. While most of the contracts specify the approved seams and/or
approved locations from which the coal is to be mined, some contracts allow the coal to be sourced from more than one mine or location.
Although the volume to be delivered pursuant to a long-term contract is stipulated, the buyers often have the option to vary the volume
within specified limits.

Reliance on Major Customers

Our two largest customers in 2004 were SSO and VEPCO. Sales to these customers in the aggregate accounted for approximately

33% of our 2004 total revenues, and sales to each of these customers accounted for 10% or more of our 2004 total revenues.

Competition

The United States coal industry is highly competitive with numerous producers in all coal producing regions. We compete with other
large producers and hundreds of small producers in the United States. The largest coal company is estimated to have sold approximately
20% of the total 2004 tonnage sold in the United States market. We compete with other coal producers primarily on the basis of coal price
at the mine, coal quality (including sulfur content), transportation cost from the mine to the customer, and the reliability of supply. Continued
demand for our coal and the prices that we obtain are also affected by demand for electricity, environmental and government regulations,
technological developments, and the availability and price of alternative fuel supplies, including nuclear, natural gas, oil, and hydroelectric
power.

Transportation

Our coal is transported to our customers by rail, truck and barge. Depending on the proximity of the customer to the mine and the
transportation available for delivering coal to that customer, transportation costs can range from 8% to 43% of the delivered cost of a
customer’s coal. As a consequence, the availability and cost of transportation constitute important factors in the marketability of coal. We
believe our mines are located in favorable geographic locations that minimize transportation costs for our customers.

Our customers pay the transportation costs from the contractual F.O.B. point (free-on-board point), which is consistent with practice
in the industry and is generally from the mine to the customer’s plant. In 2004, the largest volume transporter of our coal shipments, includ-
ing coal synfuel shipped by SSO, was the CSX railroad, which moved approximately 49% of our tonnage over its rail system. The practices
of, and rates set by, the railroad serving a particular mine or customer might affect, either adversely or favorably, our marketing efforts with
respect to coal produced from the relevant mine. At Gibson and Mettiki, independent contractors operate truck delivery systems that trans-
port the coal to Gibson and Mettiki’s primary customer’s power plants.

Regulation and Laws

The coal mining industry is subject to regulation by federal, state and local authorities on matters such as:
— employee health and safety;
— mine permits and other licensing requirements;
— air quality standards;
— water quality standards;
— storage of petroleum products and substances which are regarded as hazardous under applicable laws or which, if

spilled, could reach waterways or wetlands;

— plant and wildlife protection;
— reclamation and restoration of mining properties after mining is completed;
— the discharge of materials into the environment;
— management of solid wastes generated by mining operations;
— storage and handling of explosives;
— wetlands protection;
— management of electrical equipment containing polychlorinated biphenyls (PCBs);
— surface subsidence from underground mining;
— the effects, if any, that mining has on groundwater quality and availability; and
— legislatively mandated benefits for current and retired coal miners.

In addition, the utility industry is subject to extensive regulation regarding the environmental impact of its power generation
activities, which could affect demand for our coal. The possibility exists that new legislation or regulations, or new interpretations of exist-
ing laws or regulations, may be adopted that may have a significant impact on our mining operations or our customers’ ability to use coal,
or may require us or our customers to change our or their operations significantly or to incur substantial costs.

We are committed to conducting mining operations in compliance with applicable federal, state and local laws and regulations.
However, because of extensive and comprehensive regulatory requirements, violations during mining operations are not unusual in the
industry and, notwithstanding our compliance efforts, we do not believe these violations can be eliminated completely. None of the
violations to date or the monetary penalties assessed at our operations have been material.

While it is not possible to quantify the costs of compliance with applicable federal and state laws, those costs have been and are
expected to continue to be significant. Capital expenditures for environmental matters have not been material in recent years. We have
accrued for the present value estimated cost of reclamation and mine closings, including the cost of treating mine water discharge, when
necessary. The accruals for reclamation and mine closing costs are based upon permit requirements and the costs and timing of reclama-
tion and mine closing procedures. Although management believes it has made adequate provisions for all expected reclamation and other
costs associated with mine closures, future operating results would be adversely affected if we later determine these accruals to be insuf-
ficient. Compliance with these laws has substantially increased the cost of coal mining for all domestic coal producers.

Mining Permits and Approvals. Numerous governmental permits or approvals are required for mining operations. We may be required
to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production of coal
may have upon the environment. All requirements imposed by any of these authorities may be costly and time consuming, and may delay
or prevent commencement or continuation of mining operations in certain locations. Future legislation and administrative regulations may
emphasize more heavily the protection of the environment and, as a consequence, our activities may be more closely regulated. Legislation
and regulations, as well as future interpretations of existing laws, may require substantial increases in equipment and operating costs, or
delays, interruptions or terminations of operations, the extent of any of which cannot be predicted.

Under some circumstances, substantial fines and penalties, including revocation of mining permits, may be imposed under the laws
described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these
laws. Regulations also provide that a mining permit can be refused or revoked if the permit applicant or permittee owns or controls,
directly or indirectly through other entities, mining operations which have outstanding environmental violations. Although like other coal

companies we have been cited for violations in the ordinary course of our business, we have never had a permit suspended or revoked
because of any violation, and the penalties assessed for these violations have not been material.

Before commencing mining on a particular property, we must obtain mining permits and approvals by state regulatory authorities of
a reclamation plan for restoring, upon the completion of mining, the mined property to its approximate prior condition, productive use or
other permitted condition. Typically, we commence actions to obtain permits between 18 and 24 months before we plan to mine a new
area. In our experience, permits generally are approved within 12 months after a completed application is submitted. Generally, we have
not experienced material or significant difficulties in obtaining mining permits in the areas where our reserves are currently located.
However, the permitting process for certain mining operations has extended over several years and we cannot assure you that we will not
experience difficulty in obtaining mining permits in the future.

Our subsidiary, Mettiki Coal (WV), LLC has a proposed underground mine extension (the E-Mine) to be located primarily in Tucker
County, West Virginia, which will eventually replace Mettiki Coal’s existing long-wall in (the D-Mine) located in Garrett County, Maryland.
The proposed mine, which will be either a long-wall or continuous mining operation, is approximately 10 miles from Mettiki Coal. In order
to proceed with the development of the E-Mine, Mettiki Coal (WV) filed two separate permit applications with the West Virginia
Department of Environmental Protection (WVDEP) concerning on-site disposal of scalp rock and underground mining, each requiring an
associated water discharge permit. We were notified on April 16, May 13, May 26, and June 7, 2004, that WVDEP has issued the permits
for on-site disposal of scalp rock, underground mining, water discharge related to the operation of the scalp rock disposal facility, and water
discharge related to the operation of the underground mine, respectively.

The appeal periods for the scalp rock permit and the two water discharge permits related to the operation of the scalp rock disposal
facility and underground mine have lapsed without any appeal being filed. Two appeals of the underground mining permit were filed on
June 11 and 16, 2004, respectively. The West Virginia Surface Mine Board (SMB) consolidated the appeals and held administrative hear-
ings on October 19 and 20, 2004, December 7 and 8, 2004, and January 11 and February 7, 2005.

On March 8, 2005, the SMB issued a Final Order concluding consideration of the consolidated appeals without a decision, which Final
Order held that the SMB was unable to take any action relating to the issuance of the underground permit by WVDEP because its vote did
not obtain the concurrence of at least four SMB members as required by West Virginia law. Consequently, the ultimate decision by the
WVDEP to issue the underground permit was affirmed by operation of West Virginia law. In the Final Order, however, the SMB voted
unanimously to require Mettiki Coal (WV) to increase the amount of a surety bond that serves as security for a portion of the reclamation
plan approved by WVDEP as part of the underground permit. On March 8, 2005, Mettiki Coal (WV) filed an appeal of the Final Order with
the Circuit Court of Tucker County, West Virginia, on the ground that the SMB was wrong in ordering Mettiki Coal (WV) to increase the
surety bond for part of the reclamation plan approved by WVDEP when the SMB, as a result of not obtaining the concurrence of at least
four members, failed to affirm the decision by WVDEP to issue a final order approving the underground permit issued by WVDEP on May
13, 2004. On March 10, 2005 the West Virginia Rivers Coalition, the West Virginia Highlands Conservancy, and Trout Unlimited – West
Virginia Council filed an appeal of the SMB’s final order with the Circuit Court of Kanawha County, West Virginia. The appeal requests that
the Circuit Court (a) grant a stay of the WVDEP’s approval of the E-Mine permit pending a decision by the Circuit Court, (b) set a briefing
schedule and oral argument of the appeal and (c) reverse and vacate the WVDEP’s approval of the permit. We believe the WVDEP’s approval
of the permit application will be ultimately upheld by the applicable Circuit Court in West Virginia.

Mine Health and Safety Laws. Stringent safety and health standards have been imposed by federal legislation since 1969 when
the Coal Mine Health and Safety Act of 1969 (CMHSA) was adopted. The Federal Mine Safety and Health Act of 1977, and regulations
adopted pursuant thereto, significantly expanded the enforcement of health and safety standards and imposed comprehensive safety and
health standards on numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equip-
ment used in mining operations and other matters. The Mine Safety and Health Administration (MSHA) monitors compliance with these
federal laws and regulations. In addition, as part of CMHSA and the Mine Safety and Health Act of 1977, the Black Lung Benefits Act
requires payments of benefits by all businesses that conduct current mining operations to a coal miner with black lung disease and to some
survivors of a miner who dies from this disease. Most of the states where we operate also have state programs for mine safety and health
regulation and enforcement. In combination, federal and state safety and health regulation in the coal mining industry is perhaps the most
comprehensive and rigorous system for protection of employee safety and health affecting any segment of any industry. Even the most
minute aspects of mine operations, particularly underground mine operations, are subject to extensive regulation. This regulation has a sig-
nificant effect on our operating costs. For example, regulations governing exposures to diesel particulate matter in underground mines have

recently increased our compliance costs, and new regulations that would effectively further limit coal dust and silica exposures are under
consideration by MSHA. Our competitors in all of the areas in which we operate are subject to the same laws and regulations.

Black Lung Benefits Act (BLBA). The Federal BLBA levies a tax on production of $1.10 per ton for underground-mined coal and $0.55
per ton for surface-mined coal, but not to exceed 4.4% of the applicable sales price, in order to compensate miners who are totally dis-
abled due to black lung disease and some survivors of miners who died from this disease, and who were last employed as miners prior to
1970 or subsequently where no responsible coal mine operator has been identified for claims. In addition, BLBA provides that some claims
for which coal operators had previously been responsible will be obligations of the government trust funded by the tax. The Revenue Act
of 1987 extended the termination date of this tax from January 1, 1996, to the earlier of January 1, 2014, or the date on which the govern-
ment trust becomes solvent. For miners last employed as miners after 1969 and who are determined to have contracted black lung, we
self-insure the potential cost using actuarially determined estimates of the cost of present and future claims. We are also liable under state
statutes for black lung claims.

The U.S. Department of Labor issued revised regulations effective January 2001 altering the claims process for federal black lung

benefit recipients, which among other things:

— simplify administrative procedures for the adjudication of claims;
— propose preference for the miner’s treating physician under certain circumstances;
— allow previously denied claims to be refiled and litigated under a different standard;
— limit the amount of evidence all parties may submit for consideration;
— create a rebuttable presumption that when a miner who is eligible for black lung benefits receives medical treatment

for any pulmonary condition, the disorder is caused or aggravated by the miner’s work; and

— expand the definition of pneumoconiosis and total disability.

The revised regulations are expected to result in an increase in the incidence and recovery of black lung claims. The amount of the
increase in the incidence and recovery of black lung claims will be determined by the future application of the revised regulations in the
numerous administrative and judicial processes involved in the adjudication of black lung claims. Concerning our requirement to maintain
bonds to secure our black lung claim obligations, see the discussion of surety bonds below under Surface Mining Control and Reclamation
Act (SMCRA). In addition, Congress and state legislatures regularly consider various items of black lung legislation, which, if enacted, could
adversely affect our business, financial condition and results of operations.

Workers’ Compensation. We are required to compensate employees for work-related injuries. Several states in which we operate con-
sider changes in workers’ compensation laws from time to time. We self-insure the potential cost using actuarially determined estimates
of the cost of present and future claims. Concerning our requirement to maintain bonds to secure our workers’ compensation obligations,
see the discussion of surety bonds below under Surface Mining Control and Reclamation Act (SMCRA).

Coal Industry Retiree Health Benefits Act (CIRHBA). The Federal CIRHBA was enacted to provide for the funding of health benefits
for some United Mine Workers of America retirees. The act merged previously established union benefit plans into a single fund into which
“signatory operators” and “related persons” are obligated to pay annual premiums for beneficiaries. The act also created a second bene-
fit fund for miners who retired between July 21, 1992, and September 30, 1994, and whose former employers are no longer in business.
Because of our union-free status, we are not required to make payments to retired miners under CIRHBA, with the exception of limited pay-
ments made on behalf of predecessors of MC Mining. However, in connection with the sale of the coal assets acquired by Alliance
Resource Holdings in 1996, MAPCO Inc., now a wholly-owned subsidiary of The Williams Companies, Inc., agreed to retain, and be respon-
sible for, all liabilities under CIRHBA.

Surface Mining Control and Reclamation Act (SMCRA). The Federal SMCRA establishes operational, reclamation and closure
standards for all aspects of surface mining as well as many aspects of deep mining. The act requires that comprehensive environmental
protection and reclamation standards be met during the course of and upon completion of mining activities. In conjunction with mining the

property, we reclaim and restore the mined areas by grading, shaping and preparing the soil for seeding. Upon completion of mining, recla-
mation generally is completed by seeding with grasses or planting trees for a variety of uses, as specified in the approved reclamation
plan. We believe we are in compliance in all material respects with applicable regulations relating to reclamation.

SMCRA and similar state statutes require, among other things, that mined property be restored in accordance with specified
standards and approved reclamation plans. The act requires us to restore the surface to approximate the original contours as contempora-
neously as practicable with the completion of surface mining operations. The mine operator must submit a bond or otherwise secure the
performance of these reclamation obligations. The earliest a reclamation bond can be released is five years after reclamation has been
achieved. Federal law and some states impose on mine operators the responsibility for replacing certain water supplies damaged by
mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence,
a consequence of longwall mining and possibly other mining operations. The Federal Office of Surface Mining Reclamation and
Enforcement is currently studying the adequacy of bonding requirements for treatment of long-term pollution discharges and whether other
forms of financial assurances may be permitted. In addition, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a tax
on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The maximum tax is $0.35 per ton
on surface-mined coal and $0.15 per ton on underground-mined coal. We have accrued for the estimated costs of reclamation and mine
closing, including the cost of treating mine water discharge when necessary. In addition, states from time to time have increased and may
continue to increase their fees and taxes to fund reclamation of orphaned mine sites and AMD control on a state-wide basis, as West
Virginia did in 2002.

Under SMCRA, responsibility for unabated violations, unpaid civil penalties and unpaid reclamation fees of independent contract mine
operators and other third parties can be imputed to other companies which are deemed, according to the regulations, to have “owned” or
“controlled” the third-party violator. Sanctions against the “owner” or “controller” are quite severe and can include being blocked from
receiving new permits and revocation of any permits that have been issued since the time of the violations or, in the case of civil penalties
and reclamation fees, since the time their amounts became due. We are not aware of any currently pending or asserted claims against us
relating to the “ownership” or “control” theories discussed above. However, we cannot assure you that such claims will not develop in the
future.

In 2002, a U.S. District Court reached a decision interpreting SMCRA to prohibit subsidence from underground mining on certain
federal lands, near occupied dwelling, public or community building, public road, schools, churches, and cemeteries, or adversely affecting
public parks or certain historic properties. The U.S. Court of Appeals, District of Columbia Circuit, reversed the district court decision as
erroneous and in February 2004, the U.S. Supreme Court refused to hear an appeal of the Court of Appeals decision.

Federal and state laws require bonds to secure our obligations to reclaim lands used for mining, to pay federal and state workers’
compensation, to pay certain black lung claims, and to satisfy other miscellaneous obligations. These bonds are typically renewable on a
yearly basis. It has become increasingly difficult for us and for our competitors generally to secure new surety bonds without the posting
of partial collateral. In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favor-
able to us. Surety bonds issuers and holders may not continue to renew bonds or may demand additional collateral upon those renewals.
Our failure to maintain, or inability to acquire, surety bonds that are required by state and federal laws would have a material adverse
effect on us.

Clean Air Act (CAA). The Federal CAA and similar state laws, which regulate emissions into the air, affect coal mining and processing
operations primarily through permitting and emissions control requirements. The CAA also indirectly affects coal mining operations by
extensively regulating the air emissions of coal-fired electric power generating plants. For example, the CAA requires reduction of sulfur
dioxide (SO2) emissions from electric power generation plants in two phases. Only some facilities were subject to the Phase I requirements.
Beginning in 2000, Phase II requires nearly all facilities to reduce emissions. The affected utilities are able to meet these requirements by:

— switching to lower sulfur fuels;
— installing pollution control devices such as scrubbers;
— reducing electricity generating levels; or
— purchasing or trading so-called pollution “credits.”

Specific emissions sources receive these “credits” that utilities and industrial concerns can trade or sell to allow other units to emit
higher levels of SO2. In addition, the CAA required a study of utility power plant emissions of some toxic substances and their eventual
regulation, if warranted. As a result of that study, EPA has proposed, but not yet finalized, alternative regulatory approaches to controlling
mercury emissions from power plants. We cannot accurately predict the effect of such CAA controls on us in future years.

The CAA also indirectly affects coal mining operations by requiring utilities that currently are major sources of nitrogen oxides (NOx)
in moderate or higher ozone non-attainment areas to install reasonably available control technology for NOx, which are precursors of ozone.
In October 1998, the U.S. Environmental Protection Agency (EPA) issued a rule requiring 22 eastern states and the District of Columbia to
make substantial reductions in NOx emissions by 2003. This deadline was recently extended by EPA to 2004. EPA expects that affected
states will achieve reductions by requiring power plants to make substantial reductions in their NOx emissions. This in turn will require
power plants to install reasonably available control technology and additional control measures. Installation of reasonably available con-
trol technology and additional measures required under EPA regulations will make it more costly to operate coal-fired plants and, depend-
ing on the requirements of individual state implementation plans and the development of revised new source performance standards, could
make coal a less attractive fuel alternative in the planning and building of utility power plants in the future. Any reduction in coal’s share
of the capacity for power generation could have a material adverse effect on our business, financial condition and results of operations.
The effect these regulations, or other requirements that may be imposed in the future, could have on the coal industry in general and on
our business in particular cannot be predicted with certainty. We cannot assure you that the implementation of the CAA, the new National
Ambient Air Quality Standards (NAAQS) discussed below, or any other current or future regulatory provision, will not materially adversely
affect us.

In addition, EPA has already issued and is considering further regulations relating to fugitive dust and emissions of other coal-
related pollutants such as fine particulates. For example, in July 1997 EPA adopted new, more stringent NAAQS for particulate matter,
which may require some states to change existing implementation plans. Non-attainment designations for these NAAQS were made on
December 17, 2004. Because coal mining operations and utilities emit particulate matter, our mining operations and utility customers are
likely to be directly affected when the revisions to the NAAQS are implemented by the states. In conjunction with the mercury proposal
noted above, EPA has also proposed an Interstate Air Quality Rule which would require coal-burning power plants in 29 eastern states and
the District of Columbia to achieve greater reductions in NOx and SO2 emissions by means of a “cap and trade” program. Congress may con-
sider other controls on other air pollutants emitted by electric utilities. Such controls, if adopted, could adversely affect the market for coal.
EPA has filed suit against a number of our customers over implementation of new source performance standards and preconstruction
review requirements for new sources and major modifications under the prevention of significant deterioration and non-attainment regu-
lations. The issue raised in this litigation is what activities constitute routine maintenance, repair and replacement versus new construc-
tion. Some of our customers have agreed to or proposed settlements with EPA while others are preparing for or are engaged in litigation.
These and other regulatory developments may restrict the size of our market, and the type of coal in demand. This in turn could adversely
affect our ability to develop new mines, or could require us or our customers to modify existing operations.

Carbon Dioxide Emissions (Kyoto Protocol). The Kyoto Protocol to the United Nations Framework Convention on Climate Change calls
for developed nations to reduce their emissions of greenhouse gases to five percent below 1990 levels by 2012. Carbon dioxide, which is
a major byproduct of the combustion of coal and other fossil fuels, is subject to the Kyoto Protocol. The Kyoto Protocol went into effect on
February 16, 2005 for those nations that ratified the treaty.

In 2002, the United States withdrew its support for the Kyoto Protocol. As the Kyoto Protocol becomes effective, there will likely be
increasing international pressure on the United States to adopt mandatory restrictions on carbon dioxide emissions. In the last year, the
United States Congress has considered bills that would regulate domestic carbon dioxide emissions, but such bills have not yet received
sufficient Congressional approvals. Several states have also either passed legislation or announced initiatives focused on decreasing or
stabilizing carbon dioxide emissions associated with the combustion of fossil fuels, and many of these measures have focused on emis-
sions from coal-fired electric generating facilities.

While higher prices for natural gas and oil, and improved efficiencies and new technologies for coal-fired electric power generation
have helped to increase demand for our coal, it is possible that future federal and state initiatives to control carbon dioxide emissions could
result in increased costs associated with coal consumption, such as costs to install additional controls to reduce carbon dioxide emissions
or costs to purchase emissions reduction credits to comply with future emissions trading programs. Such increased costs for coal consump-
tion could result in some customers switching to alternative sources of fuel, which could have a material adverse effect on our business,
financial condition and results of operations.

Clean Water Act (CWA). The Federal CWA affects coal mining operations by imposing restrictions on effluent discharge into waters.
Regular monitoring, as well as compliance with reporting requirements and performance standards, are preconditions for the issuance and
renewal of permits governing the discharge of pollutants into water. Section 404 of CWA imposes permitting and mitigation requirements
associated with the dredging and filling of wetlands and streams. The CWA and equivalent state legislation, where such equivalent state
legislation exists, affect coal mining operations that impact wetlands and streams. Although permitting requirements have been tightened
in recent years, we believe we have obtained all necessary wetlands permits required under CWA §404. However, mitigation requirements
under existing and possible future wetlands permits may vary considerably. At this time we do not anticipate any increase in such require-
ments or in post-mining reclamation accrual requirements. For that reason, the setting of post-mine reclamation accruals for such mitiga-
tion projects is difficult to ascertain with certainty. We believe that we have obtained all permits required under the CWA as traditionally
interpreted by the responsible agencies. Although more stringent permitting requirements may be imposed in the future, we are not able
to accurately predict the impact, if any, of any such permitting requirements.

Each individual state is required to submit to EPA their biennial CWA §303(d) lists identifying all waterbodies not meeting state spec-
ified water quality standards. For each listed waterbody, the state is required to begin developing a Total Maximum Daily Load (TMDL) to:

— determine the maximum pollutant loading the waterbody can assimilate without violating water quality standards,
— identify all current pollutant sources and loadings to that waterbody,
— calculate the pollutant loading reduction necessary to achieve water quality standards, and
— establish a means of allocating that burden among and between the point and non-point sources contributing

polllutants to the waterbody.

We are currently participating in stakeholders meetings and in negotiations with states and EPA to establish reasonable TMDLs that
will accommodate expansion of our operations. These and other regulatory developments may restrict our ability to develop new mines, or
could require our customers or us to modify existing operations, the extent of which we cannot accurately or reasonably predict.

Safe Drinking Water Act (SDWA). The Federal SDWA and its state equivalents affect coal mining operations by imposing requirements
on the underground injection of fine coal slurries, fly ash, and flue gas scrubber sludge, and by requiring permits to conduct such under-
ground injection activities. The inability to obtain these permits could have a material impact on our ability to inject materials such as fine
coal refuse, fly ash, or flue gas scrubber sludge into the inactive areas of some of our old underground mine workings.

In addition to establishing the underground injection control program, the Federal SDWA also imposes regulatory requirements on
owners and operators of “public water systems.” This regulatory program could impact our reclamation operations where subsidence or
other mining-related problems require the provision of drinking water to affected adjacent homeowners. However, it is unlikely that any of
our reclamation activities would fall within the definition of a “public water system.” While we have several drinking water supply sources
for our employees and contractors that are subject to SDWA regulation, the SDWA is unlikely to have a material impact on our operations.

Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The Federal CERCLA, also known as the
“Superfund” law, and analogous state laws, impose liability, without regard to fault or the legality of the original conduct, on certain
classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons
include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the
hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be

subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment
and for damages to natural resources. Some products used by coal companies in operations generate waste containing hazardous sub-
stances. We are currently unaware of any material liability associated with the release or disposal of hazardous substances from our past
or present mine sites.

Resource Conservation and Recovery Act (RCRA). The Federal RCRA and corresponding state laws regulating hazardous waste affect
coal mining operations by imposing requirements for the generation, transportation, treatment, storage, disposal and cleanup of hazardous
wastes. Many mining wastes are excluded from the regulatory definition of hazardous wastes, and coal mining operations covered by
SMCRA permits are by statute exempted from RCRA permitting. RCRA also allows EPA to require corrective action at sites where there is
a release of hazardous substances. In addition, each state has its own laws regarding the proper management and disposal of waste
material. While these laws impose ongoing compliance obligations, we do not believe that these costs will have a material impact on our
operations.

Coal Combustion By-Products. In 2000, EPA declined to impose hazardous waste regulatory controls on the disposal of some coal com-
bustion by-products, including the practice of using coal combustion by-products (CCB) as mine fill. However, under pressure from environ-
mental groups, EPA has continued evaluating the possibility of placing additional solid waste burdens on the disposal of these types of
materials, and Congress has commissioned a National Academy of Sciences study of CCB mine filling to be concluded by December 2005.
EPA’s current semi-annual regulatory agent states that a rule on CCB mine filling is planned for proposal in April 2006.

While we cannot predict the ultimate outcome of the National Academy’s study or EPA’s assessment, we believe the beneficial uses
of coal combustion by-products that we employ (such as the practice of placing by-products in abandoned mine areas) do not constitute
poor environmental practices because, among other things, our CWA discharge permits for treated AMD contain parameters for pollutants
of concern, such as metals, and those permits require monitoring and reporting of effluent quality data.

Other Environmental, Health And Safety Regulation

In addition to the laws and regulations described above, we are subject to regulations regarding underground and above ground stor-
age tanks where we may store petroleum or other substances. Some monitoring equipment that we use is subject to licensing under the
Federal Atomic Energy Act. Water supply wells located on our property are subject to federal, state and local regulation.

Also, the Safe Explosives Act (SEA), a portion of the Homeland Security Act of 2002, became law on November 25, 2002. The SEA
covers all importers, manufacturers, dealers, and users of explosives. As regular users of explosives, mining companies are likely to be
under special scrutiny in its enforcement. Knowing or willful violations of SEA may result in fines, imprisonment, or both. In addition, vio-
lations of SEA may result in revocation of user permits and seizure or forfeiture of explosive materials. The SEA became effective in two
phases on January 24 and May 24, 2003.

The costs of compliance with these requirements should not have a material adverse effect on our business, financial condition or

results of operations.

Employees

To conduct our operations, our managing general partner and its affiliates employ approximately 2,020 employees, including approx-
imately 100 corporate employees and approximately 1,920 employees involved in active mining operations. Our work-force is entirely
union-free. Relations with our employees are generally good.

ITEM 2. PROPERTIES

Coal Reserves

We must obtain permits from applicable state regulatory authorities before beginning to mine particular reserves. Applications for
permits require extensive engineering and data analysis and presentation, and must address a variety of environmental, health, and safe-
ty matters associated with a proposed mining operation. These matters include the manner and sequencing of coal extraction, the storage,
use and disposal of waste and other substances and other impacts on the environment, the construction of water containment areas, and
reclamation of the area after coal extraction. We are required to post bonds to secure performance under our permits. As is typical in the
coal industry, we strive to obtain mining permits within a time frame that allows us to mine reserves as planned on an uninterrupted basis.
We begin preparing applications for permits for areas that we intend to mine sufficiently in advance of our planned mining activities to
allow adequate time to complete the permitting process. Regulatory authorities have considerable discretion in the timing of permit
issuance, and the public has rights to comment on and otherwise engage in the permitting process, including intervention in the courts. For
the reserves set forth in the table below, except for the E-mine permit discussed above in “Item 1. Business; Regulations and Laws; Mining
Permits and Approvals”, we are not currently aware of matters which would significantly hinder our ability to obtain future mining permits
on a timely basis.

Our reported coal reserves are those we believe can be economically and legally extracted and produced at the time of the filing of
this Annual Report on Form 10-K and are in accordance with guidance from SEC Industry Guide No. 7. In determining whether our reserves
meet this economical and legal standard, we take into account, among other things, our potential ability or inability to obtain a mining per-
mit, the possible necessity of revising a mining plan, changes in estimated future costs, changes in future cash flows caused by changes
in mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on selling prices.

At December 31, 2004, we had approximately 442.4 million tons of coal reserves. All of the estimates of reserves which are
presented in this Annual Report on Form 10-K are of proven and probable reserves (as defined below). For information on location of our
mines, please read “Mining Operations” under “Item 1. Business.”

The following table sets forth reserve information, at December 31, 2004, about each of our mining complexes:

Operations Mine Type

(Btus per pound)

<1.2

1.2-2.5

>2.5

Total

Assigned

Unassigned

Heat Content

Proven and Probable Reserves
Pounds S02 per MMbtu

Reserve Assignment

Illinois Basin Operations

Dotiki
Warrior
Pattiki
Hopkins

Gibson (North)
Gibson (South)

Region Total

East Kentucky Operations

Pontiki
MC Mining

Region Total

Maryland Operations

Mettiki
Mettiki Coal (WV)
Region Total
Total

% of Total

Underground
Underground
Underground
Underground
/ Surface
Underground
Underground

Underground
Underground

12,500
12,500
11,700
11,300

11,600
11,600

12,800
12,800

12,200
12,200

(tons in millions)

–
–
–
–
–
–
–
0.0

9.0
23.6
32.6

–
–
0.0
32.6

–
–
–
–
–
36.3
46.5
82.8

12.2
–
12.2

16.5
–
16.5
111.5

95.9
22.5
46.3
53.1
8.4
6.3
36.2
268.7

–
–
0.0

6.3
23.3
29.6
298.3

95.9
22.5
46.3
53.1
8.4
42.6
82.7
351.5

21.2
23.6
44.8

22.8
23.3
46.1
442.4

95.9
22.5
46.3
33.1
8.4
42.6
–
248.8

21.2
23.6
44.8

22.8
23.3
46.1
339.7

–
–
–
20.0
–
–
82.7
102.7

–
–
0.0

–
–
–
102.7

7.4 %

25.2 %

67.4 %

100.0 %

76.8 %

23.2 %

The Elk Creek reserves are reported as Hopkins County’s assigned underground reserves of 33.2 million tons in the above table. In
January 2005, we acquired Tunnel Ridge, LLC that controls 70.0 million tons in the Pittsburgh seam in West Virginia and Pennsylvania, which
tonnage figure is not reflected in the above table.

Our reserve estimates are prepared from geological data assembled and analyzed by our staff of geologists and engineers. This data
is obtained through our extensive, ongoing exploration drilling and in-mine channel sampling programs. Our drill spacing criteria adhere to
standards as defined by the U.S. Geological Survey. The maximum acceptable distance from seam data points varies with the geologic
nature of the coal seam being studied, but generally the standard for (a) proven reserves is that points of observation are no greater than
1/2 mile apart and are projected to extend as a 1/4 mile wide belt around each point of measurement and (b) probable reserves is that
points of observation are between 1/2 and 1-1/2 miles apart and are projected to extend as a 1/2 mile wide belt that lies 1/4 mile from
the points of measurement.

Reserve estimates will change from time to time to reflect evolving market conditions, mining activities,additional analyses, new
engineering and geological data, acquisition or divestment of reserve holdings, modification of mining plans or mining methods, and other
factors. Weir International Mining Consultants peformed an overview audit of all of our reserves at March 31, 1999 in conjunction with our
initial public offering.

Reserves represent that part of a mineral deposit that can be economically and legally extracted or produced, and reflect estimated
losses involved in producing a saleable product. All of our reserves are steam coal. The 32.6 million tons of reserves listed as <1.2 pounds
of SO2 per MMbtu are compliance coal.

Assigned reserves are those reserves that have been designated for mining by a specific operation.
Unassigned reserves are those reserves that have not yet been designated for mining by a specific operation.
BTU values are reported on an as shipped, fully washed, basis. Shipments that are either fully or partially raw will have a lower

BTU value.

A permit application relating to 23.3 million tons of reserves controlled by Mettiki Coal (WV) has been approved by the WVDEP.
However, the permit is subject to appeal. Please see “Item 1. Business; Regulation and Laws; Mining Permits and Approvals” above.
We control certain leases for coal deposits that are near, but not contiguous to, our primary reserve bases. The tons controlled by
these leases are classified as non-reserve coal deposits and are not included in our reported reserves. These non-reserve coal deposits are
as follows: Dotiki – 15.7 million tons, Pattiki – 3.7 million tons, Gibson (North) – 0.9 million tons, Gibson (South) – 7.5 million tons, and
Warrior – 2.1 million tons.

We lease almost all of our reserves and generally have the right to maintain leases in force until the exhaustion of minable and
merchantable coal located within the leased premises or a larger coal reserve area. These leases provide for royalties to be paid to the
lessor at a fixed amount per ton or as a percentage of the sales price. Many leases require payment of minimum royalties, payable either
at the time of the execution of the lease or in periodic installments, even if no mining activities have begun. These minimum royalties are
normally credited against the production royalties owed to a lessor once coal production has commenced.

The following table sets forth production data about each of our mining complexes:

Operations

Illinois Basin Operations

Dotiki
Warrior
Pattiki
Hopkins
Gibson (North)

Region Total

East Kentucky Operations

Pontiki
MC Mining

Region Total

Maryland Operations

Mettiki

Region Total
TOTAL

2004

Tons Produced

2003
(tons in millions)

2002

Transportation

Equipment

4.8
3.1
2.5
0.2
3.0
13.6

1.7
1.9
3.6

3.2
3.2
20.4

4.9
2.4
1.8
0.8
2.4
12.3

2.0
1.6
3.6

3.3
3.3
19.2

4.5
1.6
1.9
2.2
1.9
12.1

1.7
1.3
3.0

2.9
2.9
18.0

CSX, PAL; truck; barge
CSX, PAL; truck
CSX; barge
CSX, PAL; truck
Truck; barge

NS; truck
CSX; truck

CM
CM
CM
DL; CM
CM

CM
CM

Truck; CSX

LW; CM; CS

– CSX Railroad
– Paducah & Louisville Railroad
– Norfolk & Southern Railroad

CSX
PAL
NS
CM – Continuous Miner
– Contour Strip
CS
DL
– Dragline with Stripping Shovel, Front End Loaders and Dozers
LW – Longwall

ITEM 3. LEGAL PROCEEDINGS

We are subject to various types of litigation in the ordinary course of our business. Disputes with our customers over the provisions
of long-term coal supply contracts arise occasionally and generally relate to, among other things, coal quality, quantity, pricing, and the
existence of force majeure conditions. Other than the contract dispute with ICG described under “Other” in “Item 8. Financial Statements
and Supplementary Data – Note 17. Commitments and Contingencies,” we are not involved in any litigation involving any of our long-term
coal supply contracts. However, we cannot assure you that disputes will not occur or that we will be able to resolve those disputes in a
satisfactory manner. We are not engaged in any litigation that we believe is material to our operations, including under the various envi-
ronmental protection statutes to which we are subject. The information under “General Litigation” and “Other” under “Item 8. Financial
Statements and Supplementary Data. – Note 17. Commitments and Contingencies” is incorporated herein by this reference.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS

None.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER

PURCHASES OF EQUITY SECURITIES

The common units representing limited partners’ interests are listed on the Nasdaq National Market under the symbol “ARLP.” The
common units began trading on August 20, 1999. On March 10, 2005, the closing market price for the common units was $73.18 per unit.
As of March 10, 2005, there were 18,130,440 common units outstanding, which included 6,422,531 common units that converted from sub-
ordinated units in November 2003 and 2004. There were approximately 19,400 record holders and beneficial owners (held in street name)
of common units at December 31, 2004.

The following table sets forth the range of high and low sales prices per common unit and the amount of cash distributions declared

and paid with respect to the units, for the two most recent fiscal years:

1st Quarter 2003
2nd Quarter 2003
3rd Quarter 2003
4th Quarter 2003
1st Quarter 2004
2nd Quarter 2004
3rd Quarter 2004
4th Quarter 2004

High

Low

Distributions Per Unit

$25.500
$27.999
$29.920
$35.240
$40.910
$47.380
$56.570
$74.770

$21.490
$21.980
$25.480
$28.000
$30.510
$33.100
$44.120
$54.800

$0.5250 (paid May 15, 2003)
$0.5250 (paid August 14, 2003)
$0.5250 (paid November 14, 2003)
$0.5625 (paid February 13, 2004)
$0.625 (paid May 14, 2004)
$0.650 (paid August 2, 2004)
$0.650 (paid November 12, 2004)
$0.750 (paid February 14, 2005)

We will distribute to our partners (including holders of subordinated units), on a quarterly basis, all of our available cash. “Available
cash”, as defined in our partnership agreement, generally means, with respect to any quarter, all cash on hand at the end of each quarter,
plus working capital borrowings after the end of the quarter, less cash reserves in the amount necessary or appropriate in the reasonable
discretion of our managing general partner to (a) provide for the proper conduct of our business, (b) comply with applicable law of any debt
instrument or other agreement of ours or any of its affiliates, and (c) provide funds for distributions to unitholders and the general partners
for any one or more of the next four quarters. If quarterly distributions of available cash exceed the minimum quarterly distribution (MQD)
and certain target distribution levels as established in our partnership agreement, our managing general partner will receive distributions
based on specified increasing percentages of the available cash that exceed the MQD and the target distribution levels. Our partnership
agreement defines the MQD as $0.50 for each full fiscal quarter.

Under the quarterly incentive distribution provisions of the Partnership Agreement, our managing general partner is entitled to receive
15% of the amount we distribute in excess of $0.55 per unit, 25% of the amount we distribute in excess of $0.625 per unit, and 50% of
the amount we distribute in excess of $0.75 per unit.

Equity Compensation Plans

The information relating to our equity compensation plans required by Item 5 is incorporated by reference to such information as set

forth in “Item 12. Security Ownership of Certain Beneficial Owners and Management” contained herein.

ITEM 6. SELECTED FINANCIAL DATA

Our historical financial data below were derived from our audited consolidated financial statements as of and for the years ended
December 31, 2004, 2003, 2002, 2001 and 2000. We acquired Warrior from ARH Warrior Holdings, a subsidiary of Alliance Resource
Holdings, in February 2003. Because the Warrior acquisition was between entities under common control, it is accounted for at historical
cost in a manner similar to that used in a pooling of interests. Accordingly, the financial statements as of December 31, 2002 and 2001,
and for each of the two years in the period ended December 31, 2002, have been restated to reflect the combined historical results of oper-
ations, financial position, and cash flows of the Partnership and Warrior. ARH Warrior Holdings acquired the assets that comprise Warrior
on January 26, 2001.

(in millions, except per unit and per ton data)

Statements of Income:
Sales and operating revenues

Coal sales
Transportation revenues
Other sales and operating revenues

Total revenues

Expenses:

Operating expenses
Transportation expenses
Outside purchases
General and administrative
Depreciation, depletion and amortization
Interest expense
Unusual items (1)
Net gain from insurance settlement (2)

Total expenses
Income from operations
Other income
Income before income taxes and cumulative effect

of accounting change
Income tax expense (benefit)
Income before cumulative effect of accounting change
Cumulative effect of accounting change (3)
Net income
General Partners’ interest in net income
Limited Partners’ interest in net income
Basic net income per limited partner unit
Basic net income per limited partner unit

before accounting change

Diluted net income per limited partner unit
Diluted net income per limited partner unit

before accounting change

Weighted average number of units outstanding-basic
Weighted average number of units outstanding-diluted
Balance Sheet Data:
Working capital (deficit)
Total assets
Long-term debt
Total liabilities
Partners’ capital (deficit)
Other Operating Data:
Tons sold
Tons produced
Revenues per ton sold (4)
Cost per ton sold (5)
Other Financial Data:
Net cash provided by operating activities
Net cash used in investing activities
Net cash used in financing activities
EBITDA (6)
Maintenance capital expenditures (7)

2004

2003

2002

2001

2000

Year Ended December 31,

599.4
29.8
24.1
653.3

436.4
29.8
9.9
45.4
53.7
15.0
–
(15.2)
575.0
78.3
1.0

79.3
2.7
76.6
–
76.6
$
3.3
$
$
73.3
$ 4.09

$
$
$
$

501.6
19.5
21.6
542.7

368.8
19.5
8.5
28.3
52.5
16.0
–
–
493.6
49.1
1.4

50.5
2.6
47.9
–
47.9
0.3
47.6
2.71

$
$
$
$

479.5
19.0
20.4
518.9

367.5
19.0
10.1
20.3
52.4
16.4
–
–
485.7
33.2
0.5

33.7
(1.1)
34.8
–
34.8
(0.8)
35.6
2.31

$
$
$
$

453.1
18.2
6.2
477.5

337.2
18.2
28.9
18.7
50.7
16.8
–
–
470.5
7.0
0.8

7.8
(0.8)
8.6
7.9
16.5
(0.2)
16.7
1.09

$ 4.09
$ 3.98

$
$

2.71
2.62

$
$

2.31
2.24

$
$

0.58
1.07

$
$
$
$

$
$

347.2
13.5
2.8
363.5

257.4
13.5
16.9
15.2
39.1
16.6
(9.5)
–
349.2
14.3
1.3

15.6
–
15.6
–
15.6
0.3
15.3
0.99

0.99
0.98

$ 3.98
17,940,948
18,437,168

2.62
17,580,734
18,162,839

2.24
15,405,311
15,842,708

0.57
15,405,311
15,684,550

0.98
15,405,311
15,551,062

54.2
412.8
162.0
357.6
55.2

20.8
20.4
$ 29.98
$ 23.64

145.1
(77.6)
(46.4)
148.0
31.6

$
$

16.4
336.5
180.0
323.9
12.6

19.5
19.2
26.83
20.80

110.3
(77.8)
(31.3)
119.0
30.0

$
$

(15.8)
316.9
195.0
355.7
(38.8)

18.4
18.0
27.17
21.63

101.3
(56.9)
(46.4)
102.5
29.0

$
$

0.9
310.3
211.3
347.8
(37.6)

18.6
17.4
24.69
20.69

70.5
(31.1)
(35.2)
83.2
24.4

$
$

38.6
309.2
226.3
341.0
(31.8)

15.0
13.7
23.33
19.30

71.4
(41.0)
(31.4)
71.3
21.2

(1)

(2)

(3)

(4)

(5)

(6)

Represents income from the final resolution of an arbitrated dispute with respect to the termination of a long-term contract, net of
impairment charges relating to certain transloading facility assets, partially offset by expenses associated with other litigation
matters in 2000.

Represents the net gain from the final settlement with the Partnership’s insurance underwriters for claims relating to the Dotiki Mine
Fire Incident. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations; Summary”
for a description of the accounting treatment of expenses and insurance proceeds associated with the Dotiki Fire Incident.

Represents the cumulative effect of the change in the method of estimating coal workers’ pneumoconiosis (“black lung”) benefits lia-
bility effective January 1, 2001. Please see “Item 7. Management Discussion and Analysis of Financial Condition and Results of
Operations. – Critical Accounting Policies” and “Item 8. Financial Statements and Supplementary Data. - Note 4. Accounting Change.”

Revenues per ton sold are based on the total of coal sales and other sales and operating revenues divided by tons sold.

Cost per ton sold is based on the total of operating expenses, outside purchases and general and administrative expenses divided by
tons sold.

EBITDA is defined as net income before net interest expense, income taxes and depreciation, depletion and amortization. EBITDA is
used as a supplemental financial measure by our management and by external users of our financial statements such as investors,
commercial banks, research analysts and others, to assess:

•
•
•

•

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;
our operating performance and return on investment as compared to those of other companies in the coal energy sector,
without regard to financing or capital structures; and
the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment
opportunities.

EBITDA should not be considered as an alternative to net income, income from operations, cash flows from operating activities or any
other measure of financial performance presented in accordance with generally accepted accounting principles. EBITDA is not intended to
represent cash flow and does not represent the measure of cash available for distribution. Our method of computing EBITDA may not be
the same method used to compute similar measures reported by other companies, or EBITDA may be computed differently by us in
different contexts (i.e. public reporting versus computation under financing agreements).

The following table presents a reconciliation of the non-GAAP financial measure of EBITDA to the GAAP financial measure of

net income (in millions):

Net Income
Add:

Depreciation, depletion and amortization
Interest expense
Income tax expense (benefit)

EBITDA

2004
$ 76.6

53.7
15.0
2.7
$148.0

Year Ended December 31,
2002
$ 34.8

2003
$ 47.9

2001
$16.5

52.5
16.0
2.6
$119.0

52.4
16.4
(1.1)
$102.5

50.7
16.8
(0.8)
$83.2

2000
$15.6

39.1
16.6
–
$71.3

(7) Our maintenance capital expenditures, as defined under the terms of our partnership agreement, are those capital expenditures
required to maintain, over the long-term, the operating capacity of our capital assets. Maintenance capital expenditures for our pred-
ecessor reflect our historical designation of maintenance capital expenditures. Maintenance capital expenditures for the years ended
December 31, 2002 and 2001 have not been restated to include Warrior.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

General

The following discussion of our financial condition and results of operation should be read in conjunction with the historical financial
statements and notes thereto included elsewhere in this Annual Report on Form 10-K. We acquired Warrior from ARH Warrior Holdings, a
subsidiary of Alliance Resource Holdings, in February 2003. Because the Warrior acquisition was between entities under common control,
it is accounted for at historical cost in a manner similar to that used in a pooling of interests. Accordingly, the financial statements as of
December 31, 2002 and 2001, and for each of the two years in the period ended December 31, 2002, have beenrestated to reflect the com-
bined historical results of operations, financial position and cash flows of the Partnership and Warrior. ARH Warrior Holdings acquired
Warrior on January 26, 2001. For more detailed information regarding the basis of presentation for the following financial information,
please see “Item 8. Financial Statements and Supplementary Data. - Note 1. Organization and Presentation and Note 2. Summary of
Significant Accounting Policies.”

Business

We are a diversified producer and marketer of coal to major U.S. utilities and industrial users. In 2004, our total production was 20.4
million tons and our total sales were 20.8 million tons. The coal we produced in 2004 was approximately 32.3% low-sulfur coal, 15.7%
medium-sulfur coal and 52.0% high-sulfur coal.

At December 31, 2004, we had approximately 442.4 million tons of proven and probable coal reserves in Illinois, Indiana, Kentucky,
Maryland and West Virginia. We believe we control adequate reserves to implement our currently contemplated mining plans. In addition,
there are substantial unleased reserves on properties adjacent to some of our Illinois Basin region operations that we currently intend to
acquire or lease as our mining operations approach these areas.

In 2004, approximately 79% of our sales tonnage was consumed by electric utilities with the balance consumed by cogeneration
plants and industrial users. Our largest customers in 2004 were SSO and VEPCO. In 2004, approximately 92% of our sales tonnage, includ-
ing approximately 94% of our medium- and high-sulfur coal sales tonnage, was sold under long-term contracts. The balance of our sales
was made in the spot market. Our long-term contracts contribute to our stability and profitability by providing greater predictability of sales
volumes and sales prices. In 2004, approximately 88% of our medium- and high-sulfur coal was sold to utility plants with installed pollu-
tion control devices, also known as scrubbers, to remove sulfur dioxide.

We have entered into long-term agreements with SSO to host and operate its coal synfuel production facility currently located at
Warrior, supply the facility with coal feedstock, assist SSO with the marketing of coal synfuel and provide it with other services. These
agreements expire on December 31, 2007 and provide us with coal sales and rental and service fees from SSO based on the synfuel
facility throughput tonnages. These amounts are dependent on the ability of SSO’s members to use certain qualifying tax credits applica-
ble to the facility. The term of each of these agreements is subject to early cancellation provisions customary for transactions of these
types, including the unavailability of coal synfuel tax credits, the termination of associated coal synfuel sales contracts, and the occurrence
of certain force majeure events. We have maintained “back up” coal supply agreements with each coal synfuel customer that automati-
cally provide for sale of our coal to these customers in the event they do not purchase coal synfuel from SSO. In conjunction with a deci-
sion to relocate the coal synfuel production facility from Hopkins to Warrior, agreements for providing certain of these services were
assigned to Alliance Service, a wholly-owned subsidiary of Alliance Coal, in December 2002. Alliance Service is subject to federal and state
income taxes.

For 2004, the incremental annual net income benefit from the combination of the various coal synfuel-related agreements was approx-
imately $16.9 million, assuming that coal pricing would not have increased without the availability of synfuel. The continuation of the incre-
mental net income benefit associated with SSO’s coal synfuel facility cannot be assured. We earn income by supplying SSO’s synfuel
facility with coal feedstock, assisting SSO with the marketing of coal synfuel, and providing rental and other services. Pursuant to our
agreement with SSO, we are not obligated to make retroactive adjustments or reimbursements if SSO’s tax credits are disallowed.

In June 2003, the IRS suspended the issuance of private letter rulings on the significant chemical change requirement to qualify for
synfuel tax credits and announced that it was reviewing the test procedures and results used by taxpayers to establish that a significant
chemical change had occurred. In October 2003, the IRS completed its review and concluded that the test procedures and results were
scientifically valid if applied in a consistent and unbiased manner. The IRS has resumed issuing private letter rulings under its existing
guidelines. SSO has advised us that its private letter ruling could be reviewed by the IRS as part of a tax audit, similar to the IRS reviews
of other synfuel procedures. SSO has also advised us that the Permanent Subcommittee on Investigations of the Senate Committee on
Governmental Affairs (Subcommittee) is reviewing the synfuel industry, that the Subcommittee has indicated that they hope to interview
almost all taxpayers that are involved in the synfuel business, and that SSO has been requested to meet informally with the Subcommittee
to help enhance the Subcommittee’s knowledge of the synfuel industry.

One of our business strategies is to continue to make productivity improvements to remain a low-cost producer in each region in which
we operate. Our principal expenses related to the production of coal are labor and benefits, equipment, materials and supplies, mainte-
nance, royalties and excise taxes. Unlike most of our competitors in the eastern U.S., we employ a totally union-free workforce. Many of
the benefits of the union-free workforce are not necessarily reflected in direct costs, but we believe are related to higher productivity. In
addition, while we do not pay our customers’ transportation costs, they may be substantial and often the determining factor in a coal con-
sumer’s contracting decision. Our mining operations are located near many of the major eastern utility generating plants and on major coal
hauling railroads in the eastern U.S.

Summary. In 2004, we reported record net income of $76.6 million, an increase of 60% over 2003 net income of $47.9 million. We grew
through expansion of production capacity at Gibson, Dotiki and Pattiki, resumption of operations at the surface mine at Hopkins County
Coal, and the addition of two third-party mining operations at our Mettiki operation. Tons produced increased 5.9% to 20.4 million tons.
Tons sold increased 7.0% to 20.8 million tons.

During 2004, we benefited from strong coal markets as revenues rose to record levels and average coal sales prices in 2004 increased

11.7% compared to 2003.

We have commitments for substantially all of our 2005 production. For our estimated 2006 production, approximately 84% is com-
mitted under existing coal sales agreements and approximately 36% of the committed tonnage is subject to market price negotiations.
On December 26, 2004 the MC Mining Excel No. 3 mine was temporarily idled following the occurrence of a mine fire. The fire was
discovered by mine personnel near the bottom of the Excel No. 3 mine slope late the evening of December 25, 2004. Under a firefighting
plan developed by MC Mining, in cooperation with mine emergency response teams from the Mine Safety and Health Administration and
Kentucky Office of Mine Safety and Licensing , the four portals at the Excel No. 3 mine were capped to deprive the fire of oxygen. A series
of boreholes were then drilled into the fire area to further suppress the fire. As a result of these efforts, the mine atmosphere was ren-
dered substantially inert, or without oxygen, and the Excel No. 3 mine fire was effectively suppressed. MC Mining then began construc-
tion of temporary and permanent barriers designed to completely isolate the mine fire area. When construction of the permanent barriers
was completed, MC Mining began efforts to repair and rehabilitate the Excel No. 3 mine infrastructure. On February 21, 2005, the repair
and rehabilitation efforts had progressed sufficiently to allow initial resumption of production. We anticipate that MC Mining may return
to full production by the end of the first quarter of 2005, but we cannot assure that our ability to produce will not continue to be ad-
versely impacted by the MC Mining Fire Incident for a period of time. The boreholes continue to be used to monitor the mine atmosphere
and to inject nitrogen into the area of the fire now isolated behind the permanent barriers.

We maintain commercial property (including business interruption) insurance policies, which are renewed annually in September and
provide for self-retention and various applicable deductibles, including certain monetary and/or time element forms of deductibles, (collec-
tively the 2005 Deductibles) and 10% co-insurance (2005 Co-Insurance), but we cannot give any assurances as to the eventual timing or
amount of any recovery of proceeds under these policies. We have made initial estimates of certain costs primarily associated with activ-
ities relating to the suppression of the fire and the resumption of operations. Operating expenses for the 2004 fourth quarter increased by
$4.1 million reflecting an initial estimate of certain minimum costs attributable to the MC Mining Fire Incident that are not reimbursable
under our insurance policies due to the application of the 2005 Deductibles and 2005 Co-Insurance. An increase in the amount of such costs
is possible, but is not currently subject to a reasonable estimate at this time. In addition to these initial cost estimates, we expect to incur
additional out-of-pocket costs that will generally fall into the categories of extra expenses, expediting expenses and other areas of

coverage under the commercial insurance policies. These future out-of-pocket costs, which are not currently subject to reasonable estima-
tion, will be expensed as incurred. The related estimated insurance recovery of these costs will be recorded, net of 2005 Deductibles and
2005 Co-Insurance, as we determine that such recoveries are probable. Any recovery under the insurance policies of business interruption
proceeds attributable to amounts in excess of actual costs incurred will be recorded as gains when the claims are settled with the insur-
ance underwriters.

On February 11, 2004, Webster County Coal’s Dotiki mine was temporarily idled for a period of twenty-seven calendar days following
the occurrence of a mine fire that originated with a diesel supply tractor. As a result of the firefighting efforts of the Mine Safety and Health
Administration, Kentucky Department of Mines and Minerals, and Webster County Coal personnel, Dotiki successfully extinguished the fire
and totally isolated the affected area of the mine behind permanent barriers. Initial production resumed on March 8, 2004. For the Dotiki
Fire Incident, we had commercial property insurance that provided coverage for damage to property destroyed, interruption of business
operations, including profit recovery, and expenditures incurred to minimize the period and total cost of disruption to operations.

On September 10, 2004, we filed a third and final proof of loss with the applicable insurance underwriters reflecting a settlement (the
Dotiki Settlement) of all expenses, losses and claims incurred by Webster County Coal and other affiliates arising from or in connection
with the Dotiki Fire Incident (the Dotiki Insurance Claim) in the aggregate amount of $27.0 million, inclusive of a $1.0 million self-retention,
a $2.5 million deductible (collectively, the 2004 Insurance Deductibles) and 10% Co-Insurance (the 2004 Co-Insurance). The 2004 Insurance
Deductibles and 2004 Co-Insurance were allocated on a pro-rata basis to each of the three areas of insurance recoveries discussed below.
In addition, the accounting for two net partial advance payments in the aggregate amount of $8.1 million and the final net payment of
$13.05 million, exclusive of the 2004 Insurance Deductible and 2004 Co-Insurance, were subject to the accounting methodology described
below. Specifically, we evaluated and accounted for the insurance recoveries in the following areas:

1. Expenses incurred as a result of the fire: We incurred extra expenses, expediting expenses, and other costs associated with
extinguishing the fire in an aggregate amount of approximately $7.1 million. With application of $5.6 million of the insurance
recovery proceeds, we recorded net expenses of approximately $1.5 million.

2. Damage to Dotiki mine property: We incurred damage to Dotiki’s mine property (exclusive of any amounts relating to matters
discussed in 1. above) of approximately $1.2 million, which property had a net book value of $138,000. Based on discussions with
the underwriters culminating in the Dotiki Settlement, we recorded a net gain of approximately $785,000, reflecting the amount that
the allocated insurance proceeds exceeded the net book value of the damaged property.

3. Dotiki mine business interruption costs and extra expense: Based on the negotiations with the underwriters leading to the Dotiki
Settlement, we recorded a net gain of approximately $14.4 million for the recovery of business interruption costs and extra ex-
penses stemming from the Dotiki Fire Incident. This net gain amount reflects an offset of approximately $200,000 for professional
services expenses incurred in resolving the business interruption portion of the Dotiki Settlement.

Pursuant to the accounting methodology described above, in 2004 we recorded (a) an offset to operating expenses of approximately
$5.9 million and (b) a combined net gain of approximately $15.2 million for damage to property destroyed, interruption of business opera-
tions (including profit recovery), and extra expenses incurred to minimize the period and total cost of disruption to operations associated
with the Dotiki Fire Incident.

Results of Operations

2004 Compared with 2003

Tons sold
Tons produced
Coal Sales
Operating Expenses and Outside Purchases

2004

2003

2004

2003

Per Ton Sold

(in thousands)

20,823
20,377
$599,399
$446,384

19,467
19,238
$501,596
$377,343

N/A
N/A
$ 28.79
$ 21.44

N/A
N/A
$ 25.77
$ 19.38

Coal sales. Coal sales increased 19.5% to $599.4 million for 2004 from $501.6 million for 2003. The increase of $97.8 million reflects
higher prices on long-term coal sales agreements and the sale of additional production at significantly higher prices on short-term coal
sales agreements into the export and Central Appalachia coal markets. Higher prices on long-term contracts reflect a stronger market in
the second half of 2003 when contracts were entered into for shipments in 2004. The export market opportunities for the U.S. coal indus-
try were attributable generally to the strong economic expansion in China. The increase in Central Appalachia spot market pricing was
attributable primarily to a combination of the diversion of coal production from domestic markets to export markets and a decline in region-
wide production. Tons sold increased 7.0% to 20.8 million for 2004 from 19.5 million in 2003, primarily reflecting an increase in tons pro-
duced. Tons produced increased 5.9% to 20.4 million for 2004 from 19.2 million in 2003.

Operating expenses. Operating expenses increased 18.3% to $436.5 million in 2004 from $368.8 million in 2003. The increase of
$67.7 million was primarily attributable to (a) additional sales of 1.4 million tons, (b) higher maintenance expense and materials and
supplies costs (particularly fuel, power and steel), (c) adverse geologic conditions at the Pontiki mine, (d) increased longwall moves asso-
ciated with shorter longwall panels at the Mettiki mine and (e) additional costs associated with the MC Mining and Dotiki Fire Incidents
described above. Operating expenses include an accrual of $4.1 million reflecting our initial estimate of the minimum non-reimbursable
costs attributable to the MC Mining Fire Incident. Additionally, 2004 includes a $3.5 million buy-out expense of several coal contracts which
will allow us to take advantage of anticipated higher spot coal prices in 2005.

Other sales and operating revenues. Other sales and operating revenues, which are primarily comprised of services to the coal
synfuel production facility, increased 11.5% to $24.1 million in 2004 from $21.6 million in 2003. The increase of $2.5 million was primarily
attributable to additional rent and service fees associated with increased volumes at a third-party coal synfuel facility at Warrior.

General and administrative. General and administrative expenses for 2004 increased to $45.4 million compared to $28.3 million for
2003. The $17.1 million increase was primarily attributable to higher incentive compensation expense, which increased approximately
$16.0 million. The incentive compensation plans include the Long-Term Incentive Plan, a restricted unit plan, and the Supplemental
Executive Retirement Plan, a phantom unit plan, both of which are impacted by the increased market value of our common units, which
had a closing market price of $74.00 on December 31, 2004 compared to a closing market price of $34.38 on December 31, 2003, and
the Short-Term Incentive Plan, which provides our employees an opportunity to receive additional compensation based on our financial
performance.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased to $53.7 million in 2004 compared
to $52.5 million in 2003. The increase of $1.2 million was primarily the result of additional depreciation expense associated with increased
capital expenditures and infrastructure investments over the last few years, which have increased our production capacity. The increase
was partially offset by a $2.6 million decrease in depreciation attributable to operating Hopkins County Coal six months in 2003 compared
to three months in 2004.

Interest expense. Interest expense declined 6.4% to $15.0 million in 2004 from $16.0 million in 2003. The decrease of $1.0 million
was attributable to reduced interest expense associated with the revolving credit facility. We had no borrowings under the credit facility
during 2004.

Outside purchases. Outside purchases increased 16.5% to $9.9 million in 2004 from $8.5 million in 2003. The increase was prima-
rily attributable to an increase in outside purchases associated with our East Kentucky and Illinois Basin operations partially offset by a
decrease in the domestic brokerage market.

Transportation revenues and expenses. Transportation revenues and expenses increased 52.5% to $29.8 million in 2004 from
$19.6 million for 2003. The increase of $10.3 million was primarily attributable to increased shipments to customers that reimburse us for
transportation costs rather than arranging and paying for transportation directly with transportation providers.

Income before income tax expense (benefit). Income before income tax expense (benefit) increased 57.0% to $79.3 million for
2004 compared to $50.5 million for 2003. The increase was primarily attributable to higher sales prices, reflecting the continued strength-
ening of domestic and international coal markets, partially offset by higher operating expenses and increased general and administrative
expense, primarily attributable to higher incentive compensation expense.

Income tax expense (benefit). Income tax expense was comparable for both 2004 and 2003 at $2.6 million for each year.

2003 Compared with 2002

Tons sold
Tons produced
Coal Sales
Operating Expenses and Outside Purchases

2003

2002

2003

2002

Per Ton Sold

(in thousands)

19,467
19,238
$501,596
$377,343

18,370
17,970
$479,515
$377,644

N/A
N/A
$ 25.77
$ 19.38

N/A
N/A
$ 26.10
$ 20.56

Coal sales. Coal sales for 2003 increased 4.6% to $501.6 million from $479.5 million for 2002. The increase of $22.1 million was
attributable to increased tons sold partially offset by lower sales prices. Sales prices in 2002 benefited from coal sales agreements entered
into during the second half of 2001 when sales prices for deliveries in 2002 increased in response to a combination of factors including
low coal stockpiles and supply shortages. Tons sold increased 6.0% to 19.5 million for 2003 from 18.4 million in 2002, reflecting an increase
in tons produced. Tons produced increased 7.1% to 19.2 million for 2003 from 18.0 million in 2002. Please see “Operating Expenses” below
concerning the increase in tons produced.

Operating expenses. Operating expenses were comparable for 2003 and 2002 at $368.8 million and $367.6 million, respectively.
Increased operating expenses associated with higher production and sales levels at our active mines were offset by a decrease associat-
ed with the idling of the Hopkins complex on June 2, 2003. Operating expenses declined on a cost-per-ton sold basis as production
increased at all of our active operations except Pattiki. Pattiki’s production was essentially the same in 2003 and 2002.

Increased production reflects the absence of the adverse geologic conditions encountered at Mettiki in the third quarter of 2002 and
the emerging benefit of several strategic capital investments made during the past two years. We have added continuous miner units at
Gibson, Warrior and MC Mining and have made infrastructure investments, such as new mine shafts, at Dotiki, Warrior and MC Mining.
Additionally, operating expenses decreased due to the reversal of an expense accrual of $1.2 million established in 1998. The expense
accrual was established in conjunction with the idling of Pontiki in 1998 that created an expectation of a probable increase in workers’
compensation costs associated with the terminated workforce. The anticipated increase in workers’ compensation claims did not emerge
and, with limited exceptions, the statute of limitations expired in December 2003 for the filing or reopening of workers’compensation
claims associated with the employee terminations.

Other sales and operating revenues. Other sales and operating revenues, which is primarily comprised of services to the coal syn-
fuel production facility, increased 6.0% to $21.6 million from $20.4 million in 2002. However, the $1.2 million increase was primarily attrib-
utable to providing additional services for treating, handling and transporting coal unrelated to the coal synfuel services.

General and administrative. General and administrative expenses for 2003 increased 39.0% to $28.3 million compared to $20.3
million for 2002. The $8.0 million increase was primarily attributable to higher expense accruals of $6.9 million associated with incentive
compensation programs, and the remaining increase in expense reflects various other increases in administrative compliance costs.

Depreciation, depletion and amortization. Depreciation, depletion and amortization were comparable for 2003 and 2002 at $52.5
million and $52.4 million, respectively. Additional depreciation associated with the capital additions described in “Operating Expenses”
above was offset by lower depreciation of $3.0 million at the idled Hopkins complex. Please see “Item 1. Business, Mining Operations,
Illinois Basin Operations.”

Interest expense. Interest expense for 2003 declined 2.3% to $16.0 million from $16.4 million in 2002 primarily attributable to

decreased borrowings under the revolving credit facility.

Outside purchases. Outside purchases for 2003 decreased 15.6% to $8.5 million from $10.1 million in 2002. The decrease was

primarily attributable to a decrease in coal purchases from a third-party producer that ceased production in the fourth quarter of 2002.

Transportation revenues and expenses. Transportation revenues and expenses for 2003 increased 3.0% to 19.6 million from $19.0
million for 2002. The increase of $0.6 million was primarily attributable to the increase in tons sold. We reflect reimbursement of the cost
of transporting coal to customers through third party carriers as transportation revenues and the corresponding expense as transportation
expense in the consolidated statements of income. No margin is realized on transportation revenues.

Income before income tax expense (benefit) and cumulative effect of accounting change. Income before income tax expense
(benefit) and cumulative effect of accounting change increased 49.8% to $50.5 million for 2003 compared to $33.7 million for 2002. The
increase was primarily attributable to lower cost per-ton-sold operating costs and higher sales volumes, partially offset by lower sales
prices and increased general and administrative expenses.

Income tax expense (benefit). Income tax expense for 2003 was $2.6 million compared to an income tax benefit of $1.1 million in
2002. Although we are not a taxable entity for federal or state income tax purposes, our subsidiary, Alliance Service is subject to federal
and state income taxes. In conjunction with a decision to relocate the coal synfuel facility, agreements for a portion of the services pro-
vided to the coal synfuel producer were assigned to Alliance Service in December 2002. Approximately $2.1 million of the increase in
income tax expense was associated with coal synfuel-related services performed by Alliance Service. The balance of the income tax
expense increase was attributable to Warrior, which had a net income tax benefit for the year 2002 of approximately $1.3 million. Since
our acquisition of Warrior on February 14, 2003, the financial results of Warrior are no longer subject to federal or state income taxes.

Ongoing Acquisition Activities

Consistent with our business strategy, from time-to-time we engage in discussions with potential sellers regarding possible acquisi-

tions of certain assets and/or companies by us.

Liquidity and Capital Resources

Liquidity. We generally satisfy our working capital requirements and fund our capital expenditures and debt service obligations from cash
generated from operations and borrowings under our revolving credit facility. We believe that the cash generated from operations and our
borrowing capacity will be sufficient to meet our working capital requirements, anticipated capital expenditures (other than major capital
improvements or acquisitions), scheduled debt payments and distribution payments. To further develop available financing alternatives, in
October 2002, we entered into a master lease agreement. Under the master lease agreement, lease terms and rental payments are nego-
tiated individually when specific pieces of equipment are leased. During 2004 and 2003, we had rental expense of $1.3 million and $1.0
million, respectively, under the master lease agreement. We had no equipment leased under the master equipment lease at December 31,
2002. Our credit facility limits the amount of total operating lease obligations to $15.0 million payable in any period of 12 consecutive
months. Our ability to satisfy our obligations and planned expenditures will depend upon our future operating performance, which will be
affected by prevailing economic conditions in the coal industry, some of which are beyond our control.

Cash Flows. Cash provided by operating activities was $145.1 million in 2004, compared to $110.3 million in 2003. The increase in cash
provided by operating activities was principally attributable to an increase in net income and a greater reduction in total working capital.

Net cash used in investing activities was comparable for 2004 and 2003 at $77.6 million and $77.8 million, respectively.
Net cash used in financing activities was $46.4 million for 2004 compared to $31.3 million for 2003. The increase is primarily

attributable to the increased distributions to partners in 2004 compared to 2003.

We have various commitments primarily related to long-term debt, operating lease commitments related to buildings and equipment,
obligations for estimated reclamation and mining closing costs, capital project commitments, and pension funding. We expect to fund these
commitments with cash generated from operations, proceeds from marketable securities, and borrowings under our revolving credit
facility. The following table provides details regarding our contractual cash obligations as of December 31, 2004 (in thousands):

Contractual
Obligations

Long-term debt
Operating leases
Other long-term obligations

(excluding discount effect of $28.8
million for reclamation liability)

Capital projects

Total

$ 180,000
20,602

62,778
8,386
$ 271,766

Less
than 1
year

2-3
years

4-5
years

After 5
years

$ 18,000
4,666

$ 36,000
7,659

$ 36,000
5,467

$ 90,000
2,810

1,180
8,386
$ 32,232

6,106
–
$ 49,765

822
–
$ 42,289

54,670
–
$ 147,480

We expect to contribute $2.7 million to the defined benefit pension plan (Pension Plan) during 2005. We estimate that our interest

and income tax cash requirements will be approximately $14.3 million and $2.7 million, respectively in 2005.

Capital Expenditures. Capital expenditures decreased to $54.7 million in 2004 compared to $55.7 million in 2003, which includes the
acquisition of Warrior Coal. Excluding the Warrior acquisition, capital expenditures for 2004 increased $11.7 million compared to capital
expenditures for the 2003 period. The increase in capital expenditures is associated with Dotiki expanding its preparation plant and adding
two continuous miners, and the addition of one continuous mining unit at Gibson and Pattiki.

In February 2003, we acquired Warrior from an affiliate, ARH Warrior Holdings, pursuant to the terms of a previously existing agree-
ment. Warrior owns an underground mining complex located between and adjacent to our other western Kentucky operations near
Madisonville, Kentucky. We paid $12.7 million to ARH Warrior Holdings in accordance with the terms of an Amended and Restated Put and
Call Option Agreement. In addition, we repaid Warrior’s borrowings of $17.0 million under the revolving credit agreement between our spe-
cial general partner and Warrior. We funded the Warrior acquisition through a portion of the proceeds received from the issuance of
2,250,000 common units in February 2003.

We currently project that our average annual maintenance capital expenditures will be approximately $50.0 million. We also currently
expect to fund our anticipated total capital expenditures for 2005 of $79.9 million, with cash generated from operations and borrowings
under our revolving credit facility described below.

Notes Offering and Credit Facility. Alliance Resource Operating Partners, L.P., our intermediate partnership, has $180 million principal
amount of 8.31% senior notes due August 20, 2014, payable in ten equal annual installments of $18 million beginning in August 2005 with
interest payable semi-annually (Senior Notes). On August 22, 2003, our intermediate partnership completed an $85 million revolving credit
facility (Credit Facility), which expires September 30, 2006. The Credit Facility replaced a $100 million credit facility that would have expired
August 2004. We paid in full all amounts outstanding under the $100 million original credit facility with borrowings of $20 million under
the Credit Facility. The interest rate on the Credit Facility is based on either the (i) London Interbank Offered Rate or (ii) the “Base Rate”,
which is equal to the greater of the JPMorgan Chase Prime Rate or the Federal Funds Rate plus 1/2 of 1%, plus, in either case, an appli-
cable margin. We incurred certain costs aggregating $1.2 million associated with the Credit Facility. These costs have been deferred and
are being amortized as a component of interest expense over the term of the Credit Facility. We had no borrowings outstanding under the
Credit Facility at December 31, 2004. Letters of credit can be issued under the Credit Facility not to exceed $30 million. Outstanding letters
of credit reduce amounts available under the Credit Facility. At December 31, 2004, we had letters of credit of $9.0 million outstanding
under the Credit Facility.

The Senior Notes and Credit Facility are guaranteed by all of the subsidiaries of our intermediate partnership. The Senior Notes and
Credit Facility contain various restrictive and affirmative covenants, including restrictions on the amount of distributions by our intermedi-
ate partnership and the incurrence of other debt. We were in compliance with the covenants of both the Credit Facility and Senior Notes at
December 31, 2004.

We have previously entered into and have maintained agreements with two banks to provide additional letters of credit in an
aggregate amount of $25.0 million to maintain surety bonds to secure our obligations for reclamation liabilities and workers’ compensa-
tion benefits. At December 31, 2004, we had $22.2 million in letters of credit outstanding under these agreements. Our special general
partner guarantees the letters of credit.

Critical Accounting Policies

From our Summary of Significant Accounting Policies, we have identified the following accounting policies that require the exercise of
our most difficult, complex and subjective levels of judgment. Our judgments in the following areas are principally based on estimates and
assumptions that affect the reported amounts and disclosures in the consolidated financial statements. Please see “Item 8. Financial
Statements and Supplementary Data.” Actual results that are influenced by future events could materially differ from the current estimates.

Long-Lived Assets. We review the carrying value of long-lived assets whenever events or changes in circumstances indicate that the
carrying amount may not be recoverable based upon estimated undiscounted future cash flows. The amount of impairment is measured by
the difference between the carrying value and the fair value of the asset, which is based on cash flows from that asset, discounted at a
rate commensurate with the risk involved. Events or changes in circumstance that could cause us to perform such a review include, but are
not limited to, the loss of a major coal supply agreement, a significant decline in demand for our coal and an adverse change in geologic
conditions.

Reclamation and Mine Closing Costs. The Federal SMCRA and similar state statutes require that mine property be restored in accor-
dance with specified standards and an approved reclamation plan. We record the liability for the estimated cost of future mine reclama-
tion and closing procedures on a present value basis when incurred, and the associated cost is capitalized by increasing the carrying
amount of the related long-lived asset. Those costs relate to sealing portals at underground mines and to reclaiming the final pit and sup-
port acreage at surface mines. Other costs common to both types of mining are related to removing or covering refuse piles and settling
ponds, and dismantling preparation plants, other facilities and roadway infrastructure. We had accrued liabilities of $34.0 million and $23.5
million for these costs at December 31, 2004 and 2003, respectively. The liability for mine reclamation and closing procedures is sensitive
to changes in cost estimates and estimated mine lives.

Workers’ Compensation and Pneumoconiosis (“Black Lung”) Benefits. We provide income replacement and medical treatment for
work-related traumatic injury claims as required by applicable state laws. We provide for these claims through self-insurance programs.
The liability for traumatic injury claims is the estimated present value of current workers’ compensation benefits, based on an annual
independent actuarial study. The actuarial calculations are based on a blend of actuarial projection methods and numerous assumptions
including development patterns, mortality, medical costs and interest rates. We had accrued liabilities of $32.6 million and $28.7 million
for these costs at December 31, 2004 and 2003, respectively. A one-percentage-point reduction in the discount rate would have increased
the liability at December 31, 2004 approximately $1.8 million, which would have a corresponding increase in operating expenses.

Coal mining companies are subject to the Federal Coal Mine Health and Safety Act of 1969, as amended, and various state statutes
for the payment of medical and disability benefits to eligible recipients related to coal worker’s pneumoconiosis (“black lung”). We provide
for these claims through self-insurance programs. Our estimated black lung liability is based on an annual actuarial study performed by an
independent actuary. The actuarial calculations are based on numerous assumptions including disability incidence, medical costs,
mortality, death benefits, dependents and interest rates. We had accrued liabilities of $20.3 million and $17.6 million for these benefits at
December 31, 2004 and 2003, respectively. A one-percentage-point reduction in the discount rate would have increased the expense rec-
ognized for the year ended December 31, 2004 by approximately $0.9 million. Under the service cost method used to estimate our black
lung benefits liability, actuarial gains or losses attributable to changes in actuarial assumptions such as the discount rate are amortized
over the remaining service period of active miners.

Universal Shelf

In April 2002, we filed with the Securities and Exchange Commission a universal shelf registration statement allowing us to issue
from time-to-time up to an aggregate of $200 million of debt or equity securities. At March 1, 2005, we had approximately $142.9 million
available under this registration statement.

Related Party Transactions

Administrative Services. Our partnership agreement provides that our managing general partner and its affiliates be reimbursed for all
direct and indirect expenses they incur or payments they make on our behalf including, but not limited to, management’s salaries and
related benefits (including incentive compensation), and accounting, budget, planning, treasury, public relations, land administration,
environmental, permitting, payroll, benefits, disability, workers’ compensation management, legal and information technology services. Our
managing general partner may determine in its sole discretion the expenses that are allocable to us. Total costs billed by our managing
general partner and its affiliates to us were approximately $28,536,000, $12,471,000, and $6,559,000 for the years ended December 31,
2004, 2003, and 2002, respectively. The increases from 2003 to 2004 and 2002 to 2003 were primarily attributable to higher accruals
related to common unit based incentive plans, which were impacted by the increased market value of our common units, and the Short
Term Incentive Plan (STIP).

Warrior Acquisition. On February 14, 2003, we acquired Warrior from an affiliate, ARH Warrior Holdings a subsidiary of Alliance
Resource Holdings, pursuant to an Amended and Restated Put and Call Option Agreement (Put/Call Agreement). Warrior purchased the
capital stock of Roberts Bros. Coal Co., Inc., Warrior Coal Mining Company, Warrior Coal Corporation and certain assets of Christian Coal
Corp. and Richland Mining Co., Inc. in January 2001. Our managing general partner had previously declined the opportunity to purchase
these assets as we had previously committed to major capital expenditures at two existing operations. As a condition to not exercising its
right of first refusal, we requested that ARH Warrior Holdings enter into a put and call arrangement for Warrior. We and ARH Warrior
Holdings, with the approval of the conflicts committee of our managing general partner, entered into the Put/Call Agreement in January
2001. Concurrently, ARH Warrior Holdings acquired Warrior in January 2001 for $10.0 million.

The Put/Call Agreement preserved the opportunity for us to acquire Warrior during a specified time period. Under the terms of the
Put/Call Agreement, ARH Warrior Holdings exercised its put option requiring us to purchase Warrior at a put option price of approximately
$12.7 million.

The option provisions of the Put/Call Agreement were subject to certain conditions (unless otherwise waived), including, among
others, (a) the non-occurrence of a material adverse change in the business and financial condition of Warrior, (b) the prohibition of any
dividends or other distributions to Warrior’s shareholders, (c) the maintenance of Warrior’s assets in good working condition, (d) the prohi-
bition on the sale of any equity interest in Warrior except for the options contained in the Put/Call Agreement, and (e) the prohibition on
the sale or transfer of Warrior’s assets except those made in the ordinary course of its business.

The Put/Call Agreement option prices reflected negotiated sale and purchase amounts that both parties determined would allow each
party to satisfy acceptable minimum investment returns in the event either the put or call options were exercised. In January 2001 and in
December 2002, we developed financial projections for Warrior based on due diligence procedures we customarily perform when consid-
ering the acquisition of a coal mine. The assumptions underlying the financial projections made by us for Warrior included, among others,
(a) annual production levels ranging from 1.5 million to 1.8 million tons, (b) coal prices at or below the then current coal prices and (c) a
discount rate of 12 percent. Based on these financial projections, as of the date of the acquisition and at December 31, 2002 and 2001, we
believe that the fair value of Warrior was equal to or greater than the put option exercise price.

The put option price of $12.7 million was paid to ARH Warrior Holdings in accordance with the terms of the Put/Call Agreement. In
addition, we repaid Warrior’s borrowings of $17.0 million under the revolving credit agreement between our special general partner and
Warrior. The primary borrowings under the revolving credit agreement financed new infrastructure capital projects at Warrior that have
contributed to improved productivity and significantly increased capacity. We funded the Warrior acquisition through a portion of the
proceeds received from the issuance of 2,250,000 common units. Because the Warrior acquisition was between entities under common
control, it has been accounted for at historical cost in a manner similar to that used in a pooling of interests.

Under the terms of the Put/Call Agreement, we assumed certain other obligations, including a mineral lease and sublease with SGP
Land, a subsidiary of our special general partner, covering coal reserves that have been and will continue to be mined by Warrior. The terms
and conditions of the mineral lease and sub-lease remain unchanged.

SGP Land. Dotiki has a mineral lease and sublease with SGP Land requiring annual minimum royalty payments of $2.7 million, payable in
advance through 2013 or until $37.8 million of cumulative annual minimum and/or earned royalty payments have been paid. Dotiki paid
royalties of $4,611,000, $3,460,000, and $2,700,000 for the years ended December 31, 2004, 2003 and 2002, respectively. Dotiki has
recouped as earned royalties all advance minimum royalty payments made under these lease terms except for $805,000 as of December
31, 2004.

Warrior has a mineral lease and sublease with SGP Land. Under the terms of the lease, Warrior has paid and will continue to pay in
arrears an annual minimum royalty obligation of $2,270,000 until $15,890,000 of cumulative annual minimum and/or earned royalty pay-
ments have been paid. The annual minimum royalty periods are from October 1st through the end of the following September, expiring
September 30, 2007. Warrior paid royalties of $2,561,000, $2,453,000, and $2,127,000 for the years ended December 31, 2004, 2003, and
2002, respectively. Warrior has recouped as earned royalties all advance minimum royalty payments made in accordance with these lease
terms except for $636,000 as of December 31, 2004.

Under the terms of the mineral lease and sublease agreements described above, Dotiki and Warrior also reimbursed SGP Land for
SGP Land’s base lease obligations. We reimbursed SGP Land $5,428,000, $4,395,000, and $3,922,000 for the years ended December 31,
2004, 2003 and 2002 respectively, for the base lease obligations. Dotiki and Warrior have recouped as earned royalties all advance mini-
mum royalty payments made in accordance with these terms except for $216,000 as of December 31, 2004.

In 2001, SGP Land, as successor in interest to an unaffiliated third party, entered into an amended mineral lease with MC Mining.
Under the terms of the lease, MC Mining has paid and will continue to pay an annual minimum royalty obligation of $300,000 until $6.0
million of cumulative annual minimum and/or earned royalty payments have been paid. MC Mining paid royalties of $479,000 and $568,000
for the years ended December 31, 2003 and 2002, respectively. The 2004 annual minimum royalty obligation of $300,000 was paid in
January 2005. MC Mining has recouped as earned royalties all advance minimum royalty payments made under these lease terms as of
December 31, 2004.

We also have an option to lease and/or sublease certain reserves from SGP Land, which reserves are contiguous to Hopkins. Under
the terms of the option to lease and sublease, we paid option fees of $1,368,000 and $684,000 during the years ended December 31, 2004
and 2003, respectively. The 2003 option fee of $684,000 was paid in January 2004 and is included in the due to affiliates balance as of
December 31, 2003. The anticipated annual minimum royalty obligation is $684,000, payable in advance through 2009.

Special General Partner. Effective January 2001, Gibson entered into a noncancelable operating lease arrangement with our special
general partner for its coal preparation plant and ancillary facilities. Based on the terms of the lease, Gibson has paid and will continue to
make monthly payments of approximately $216,000 through January 2011. Lease expense was $2,595,000 for 2004, 2003 and 2002.

We have previously entered into and have maintained agreements with two banks to provide letters of credit in an aggregate amount
of $25.0 million to maintain surety bonds to secure our obligations for reclamation liabilities and workers’ compensation benefits. At
December 31, 2004, we had $22.2 million in out-standing letters of credit. Our special general partner guarantees these letters of credit.
Historically, we have compensated our special general partner a guarantee fee equal to 0.30% per annum of the face amount of the let-
ters of credit outstanding. Our special general partner agreed to waive the guarantee fee in exchange for a parent guarantee from our inter-
mediate partnership and Alliance Coal on the mineral lease and sublease with Dotiki and Warrior. We paid approximately $31,300 and
$48,200 in guarantee fees to our special general partner for the years ended December 31, 2003 and 2002, respectively.

The Elk Creek reserve area encompasses approximately 9,000 acres and is contiguous to our Hopkins County Coal complex. The Elk
Creek coal reserves are currently estimated to include approximately 30 million tons of high-sulfur coal. The Elk Creek mine will be an
underground mining complex, that mines the West Kentucky No. 9 and No. 11 coal seams. It will utilize continuous mining units and employ
room-and-pillar mining techniques. We intend to use the existing coal handling and other surface facilities owned by Hopkins County Coal.
We anticipate the Elk Creek complex will employ as many as 250 individuals and produce up to 3.2 million tons of coal annually. We esti-
mate total capital expenditures to develop Elk Creek to be approximately $65.0 million. In December, 2004, the board of directors of our
managing general partner approved the capital expenditures associated with Elk Creek. Coal supply commitments are currently being pur-
sued. Construction of the Elk Creek mining complex began in the first quarter of 2005. We expect to fund these capital expenditures with
available cash and marketable securities on hand, future cash generated from operations and borrowings available under our revolving
credit facility.

In January 2005, we acquired 100% of the limited liability company member interests of Tunnel Ridge, LLC for approximately $500,000
and the assumption of reclamation liabilities from Alliance Resource Holdings, Inc., a company owned by our management. Tunnel Ridge,
LLC controls through a coal lease agreement with the special general partner an estimated 70 million tons of high-sulfur coal in the
Pittsburgh No. 8 coal seam. The Tunnel Ridge reserve area encompasses approximately 50,571 acres of land located in Ohio County, West
Virginia and Washington County, Pennsylvania. Under the terms of the coal lease, beginning on January 1, 2005, Tunnel Ridge, LLC began
paying our special general partner an advance minimum royalty of $3.0 million per year, which advance royalty payments will be fully
recoupable against earned royalties. The earned royalty rate under the coal lease is the greater of $0.75 per ton or 3.0% of the per ton
gross sales price f.o.b. barge. The term of the coal lease is the earlier of 30 years or until exhaustion of all mineable and merchantable
coal with termination rights after the initial four years of the coal lease.

Tunnel Ridge, LLC also controls, under a separate lease agreement with our special general partner, the rights to approximately 900
acres of surface land and other tangible assets. Under the terms of the lease agreement, Tunnel Ridge, LLC shall pay our special general
partner an annual lease payment of $240,000 beginning January 1, 2005. The lease agreement has an initial term of four years, which term
may be extended by Tunnel Ridge, LLC at the same annual lease payment rate, to be consistent with the term of the coal lease.

We have initiated the permitting process of the Tunnel Ridge reserve area. We anticipate that the Tunnel Ridge operation will use a
longwall miner for the majority of its coal extraction as well as continuous mining units used for preparation of the mine for future long-
wall mining. We estimate the Tunnel Ridge operation will be designed to produce up to six million tons of coal annually. We believe pro-
duction from Tunnel Ridge may begin as early as 2008. We anticipate the Tunnel Ridge complex will employ as many as 300 individuals.
We estimate total capital expenditures required to develop Tunnel Ridge to be approximately $200 million over a five-year period. We cur-
rently expect to fund these capital expenditures with available cash and marketable securities, future cash generated from operations and
borrowings available under our revolving credit facility. A definitive commitment to develop Tunnel Ridge is dependent upon final approval
by the board of directors of our managing general partner.

Accruals of Other Liabilities

We had accruals for other liabilities, including current obligations, totaling $101.1 million and $77.8 million at December 31, 2004 and
2003. These accruals were chiefly comprised of workers’ compensation benefits, black lung benefits, and costs associated with reclama-
tion and mine closings. These obligations are self-insured. The accruals of these items were based on estimates of future expenditures
based on current legislation, related regulations and other developments. Thus, from time to time, our results of operations may be signif-
icantly affected by changes to these liabilities. Please see “Item 8. Financial Statements and Supplementary Data. - Note 14. Reclamation
and Mine Closing Costs and Note 15. Pneumoconiosis (“Black Lung”) Benefits.”

Pension Plan

We maintain a Pension Plan, which covers certain employees at the mining operations.
Our pension expense was approximately $2,751,000 and $3,049,000 for the years ended December 31, 2004 and 2003, respectively.
The pension expense is based upon a number of actuarial assumptions, including an expected long-term rate of returns on our Pension Plan
assets of 8.0% and 8.0% and discount rates of 6.25% and 6.75% for the years ended December 31, 2004 and 2003, respectively. Our
actual return on plan assets was 11.9% and 25.9% for the years ended December 31, 2004 and 2003, respectively. Additionally, we base
our determination of pension expense on an unsmoothed market-related valuation of assets equal to the fair value of assets, which imme-
diately recognizes all investment gains or losses.

In developing our expected long-term rate of return assumption, we evaluated input from our investment manager, including their
review of asset class return expectations by economists, and our actuary. At January 1, 2005, our expected long-term return assumption
is at least 8.0%. Our advisors base the projected returns on broad equity and bond indices. Our expected long-term rate of return on Pension
Plan assets is based on an asset allocation assumption of 80.0% with equity managers, with an expected long-term rate of return of 10.4%,
and 20.0% with fixed income managers, with an expected long-term rate of return of 5.4%. The pension plan trustee regularly reviews our
actual asset allocation in accordance with our investment guidelines and periodically rebalanced our investments to our targeted alloca-
tion when considered appropriate. The investment committee reviews our asset allocation with the compensation committee annually.

The discount rate that we utilize for determining our future pension obligation is based on a review of currently available high-
quality fixed-income investments that receive one of the two highest ratings given by a recognized rating agency. We have historically used
the average monthly yield for December of an Aa-rated utility bond index as the primary benchmark for establishing the discount rate. The
duration of the bonds that comprise this index is comparable to the duration of the benefit obligation in the Pension Plan. The discount rate
determined on this basis decreased from 6.25% at December 31, 2003 to 5.75% at December 31, 2004.

We estimate that our Pension Plan expense and cash contributions will be approximately $3,240,000 and $2,700,000, respectively in
2005. Future actual pension expense and contributions will depend on future investment performance, changes in future discount rates and
various other factors related to the employees participating in the Pension Plan.

Lowering the expected long-term rate of return assumption by 1.0% (from 8.0% to 7.0%) at December 31, 2003 would have increased
our pension expense for the year ended December 31, 2004 by approximately $211,000. Lowering the discount rate assumption by 0.5%
(from 6.25% to 5.75%) at December 31, 2003 would have increased our pension expense for the year ended December 31, 2004 by approx-
imately $422,000.

Inflation

Inflation in the U.S. has been relatively low in recent years and did not have a material impact on our results of operations for the
three years in the period ended December 31, 2004. However, in 2004 an increase in the cost of steel, power and fuel has increased,
directly and indirectly, our materials, supplies and maintenance costs.

New Accounting Standards

In November 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No.
151, Inventory Costs. SFAS No. 151 is an amendment of Accounting Research Bulletin (ARB) No. 43, chapter 4, paragraph 5 that deals
with inventory pricing. SFAS No. 151 clarifies the accounting for abnormal amounts of idle facility expenses, freight, handling costs, and
spoilage. Under previous guidance, paragraph 5 of ARB No. 43, chapter 4, items such as idle facility expense, excessive spoilage, double
freight, and rehandling costs might be considered to be so abnormal, under certain circumstances, as to require treatment as current peri-
od charges. This Statement eliminates the criterion of “so abnormal” and requires that those items be recognized as current period charges.
Also, SFAS No. 151 requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of
the production facilities. SFAS No. 151 is effective for fiscal years beginning after June 15, 2005. We are currently analyzing the require-
ments of SFAS No. 151 and believe that its adoption will not have any significant impact on our financial position, results of operations
or cash flows.

In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment. SFAS No. 123R is a revision of SFAS No. 123,
Accounting for Stock Based Compensation, and supersedes APB 25. Among other items, SFAS No. 123R eliminates the use of APB 25 and
the intrinsic value method of accounting, and requires companies to recognize the cost of employee services received in exchange for
awards of equity instruments, based on the grant date fair value of those awards, in the financial statements.

The effective date of SFAS No. 123R is the first reporting period beginning after June 15, 2005, and we expect to adopt SFAS No.
123R effective July 1, 2005. SFAS No. 123R permits companies to adopt its requirements using either a “modified prospective” method, or
a “modified retrospective” method. Under the “modified prospective” method, compensation cost is recognized in the financial statements
beginning with the effective date, based on the requirements of SFAS No. 123R for all share-based payments granted after that date, and
based on the requirements of SFAS No. 123 for all unvested awards granted prior to the effective date of SFAS No. 123R. Under the “mod-
ified retrospective” method, the requirements are the same as under the “modified prospective” method, but also permits entities to
restate financial statements of previous periods based on proforma disclosures made in accordance with SFAS No. 123. We are currently
evaluating the appropriate transition method.

As permitted by SFAS No. 123, we currently account for share based payments to employees using the APB No. 25 intrinsic method
and related FASB Interpretation No. 28 based upon the current market value of our common units at the end of each period. We have
recorded compensation expense of $20,320,000, $7,687,000 and $2,338,000 for the years ended December 31, 2004, 2003 and 2002,
respectively. SFAS No. 123R does not permit entities to continue to use the intrinsic method, we have not yet determined which model we
will use to measure the fair value of restricted unit-based compensation upon the adoption of SFAS No. 123R.

Risk Factors

If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially

adversely affected and the trading price of our common units could decline.

Risks Inherent in Our Business

–

A substantial or extended decline in coal prices could negatively impact our results of operations.

A material portion of our net income and cash flow is dependent on the continued ability by us or others to realize benefits from
state and federal tax credits. If the benefit to us from any of these tax credits is materially reduced, it could have a material
adverse effect on our operations and might impair our ability to pay the distributions on our units.

Competition within the coal industry may adversely affect our ability to sell coal, and excess production capacity in the industry
could put downward pressure on coal prices.

Newly constructed power plants may be fueled by natural gas. Any change in consumption patterns by utilities, away from the
use of coal, could affect our ability to sell the coal we produce.

From time to time conditions in the coal industry may make it more difficult for us to extend existing or enter into new long-term
contracts. This could affect the stability and profitability of our operations.

Some of our long-term contracts contain provisions allowing for the renegotiation of prices and, in some instances, the termina-
tion of the contract or the suspension of purchases by customers.

Some of our long-term contracts require us to supply all of our customers’ coal needs. If these customers’ coal requirements
decline, our revenues under these contracts will also drop.

A substantial portion of our coal has a high-sulfur content. This coal may become more difficult to sell because the Clean Air Act
may impact the ability of electric utilities to burn high-sulfur coal through the regulation of emissions.

– We depend on a few customers for a significant portion of our revenues, and the loss of one or more significant customers could

impact our ability to sell the coal we produce.

–

Litigation relating to disputes with our customers may result in substantial costs, liabilities and loss of revenues.

The term of each of the agreements associated with the coal synfuel agreements is subject to early cancellation provisions
customary for transactions of these types, including the unavailability of synfuel tax credits, the termination of associated coal
synfuel sales contracts, and the occurrence of certain force majeure events. Therefore, the continuation of the operating
revenues associated with coal synfuel cannot be assured.

Coal mining is subject to inherent risks that are beyond our control and these risks may not be fully covered under our insurance
policies. These risks include fires and explosions from methane, natural disasters like floods, mining and processing equipment
failures, changes or variations in geologic conditions, inability to acquire mining rights or permits, employee injuries or fatali-
ties, and labor-related interruptions.

–

Although none of our employees are members of unions, our work force may not remain union-free in the future.

Any significant increase in transportation costs or disruption of the transportation of our coal may impair our ability to sell coal.

– We may not be able to grow successfully through future acquisitions, and we may not be able to effectively integrate the

various businesses or properties we do acquire.

–

Our business will be adversely affected if we are unable to replace our coal reserves.

The estimates of our reserves may prove inaccurate, and unitholders should not place undue reliance on these estimates.

Cash distributions are not guaranteed and may fluctuate with our performance. In addition, our managing general partner’s dis-
cretion in establishing cash reserves may negatively impact a unitholder’s receipt of cash distributions.

Our indebtedness may limit our ability to borrow additional funds, make distributions to unitholders or capitalize on business
opportunities.

Risks Inherent in an Investment in the Partnership

–

The president and chief executive officer of our managing general partner effectively controls us through his ownership of a
majority of the equity interests in our managing general partner and affiliates.

–

Unitholders have limited voting rights and do not control our managing general partner.

– We may issue additional common units without the approval of common unitholders, which would dilute existing unitholders’

interests.

–

The issuance of additional common units will increase the risk that we will be unable to pay the full minimum quarterly
distribution on all common units.

Cost reimbursements to our general partners may be substantial and will reduce our cash available for distribution.

Our managing general partner has a limited call right that may require unitholders to sell their common units at an undesirable
time or price.

Unitholders may not have limited liability under some circumstances.

Our general partners and their affiliates, which are controlled by our management, may in some instances engage in activities
that compete directly with us.

Regulatory Risks

– We are subject to federal, state and local regulations on health, safety, environmental and numerous other matters. These reg-

ulations increase our costs of doing business, or discourage customers from buying our coal.

– We have black lung benefits and workers’ compensation obligations that could increase if new legislation is enacted.

–

The Clean Air Act affects our customers and could significantly influence their purchasing decisions. New regulations under the
Clean Air Act could also reduce demand for our coal.

The passage of state and federal legislation responsive to concerns over emissions of greenhouse gases such as carbon
dioxide could result in a reduced use of coal by electric power generators. Any such reduction in use could adversely affect our
revenues and results of operations.

– We are subject to the Clean Water Act which imposes limitations, and monitoring and reporting obligations, on our discharge
of pollutants into water. Those limitations and obligations may become more stringent and result in restricted operations and
increased costs.

– We are subject to the Safe Drinking Water Act, which imposes various requirements on us through coal refuse disposal under

the underground injection control program or regulation of our public drinking water systems.

– We are subject to reclamation, mine closure and real property restoration regulatory obligations and must accrue for the

estimated cost of complying with these regulations.

– We could incur significant costs under federal and state Superfund and waste management statutes.

Tax Risks to Common Unitholders

–

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject
to entity-level taxation by states. If the IRS treats us as a corporation or we become subject to entity-level taxation for state tax
purposes, it would substantially reduce distributions to our unitholders and our ability to make payments on our debt
securities.

– We have not requested an IRS ruling with respect to our tax treatment.

–

You may be required to pay taxes on income from us even if you receive no cash distributions.

Tax gain or loss on disposition of common units could be different than expected.

Common unitholders, other than individuals who are U.S. residents, may experience adverse tax consequences from owning
common units.

– We have registered with the IRS as a tax shelter. This may increase the risk of an IRS audit of us or a common unitholder.

– We treat a purchaser of common units as having the same tax benefits as the seller. The IRS may challenge this treatment, which

could adversely affect the value of common units.

–

Common unitholders will likely be subject to state and local taxes as a result of an investment in common units.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We have significant long-term coal supply agreements. Virtually all of the long-term coal supply agreements are subject to price
adjustment provisions, which permit an increase or decrease periodically in the contract price to principally reflect changes in specified
price indices or items such as taxes, royalties or actual production costs. For additional discussion of coal supply agreements, please see
“Item 1. Business. – Coal Marketing and Sales” and “Item 8. Financial Statements and Supplementary Data. – Note 17. Concentration of
Credit Risk and Major Customers.”

Almost all of our Predecessor’s transactions were, and all of our transactions are, denominated in U.S. dollars, and as a result, we do

not have material exposure to currency exchange-rate risks.

At the current time, we do not have any interest rate, foreign currency exchange rate or commodity price-hedging transactions

outstanding.

On August 22, 2003, our intermediate partnership completed an $85 million revolving credit facility which replaces a $100 million
credit facility. Borrowings under the credit facility and the previous credit facility are and were at variable rates and, as a result, we have
interest rate exposure. Our earnings are not materially affected by changes in interest rates. We had no borrowings outstanding under the
Credit Facility during 2004 or at December 31, 2004.

The table below provides information about our market sensitive financial instruments and constitutes a “forward-looking statement.”
The fair values of long-term debt are estimated using discounted cash flow analyses, based upon our current incremental borrowing rates
for similar types of borrowing arrangements as of December 31, 2004, and 2003. The carrying amounts and fair values of financial instru-
ments are as follows (in thousands):

Expected Maturity Dates
as of December 31, 2004

Senior Notes fixed rate
Weighted Average interest rate

Expected Maturity Dates
as of December 31, 2003

Senior Notes fixed rate
Weighted Average interest rate

2005

2006

2007

2008

2009

Thereafter

Total

Fair Value
December 31,
2004

$ 18,000

$ 90,000

$ 180,000

$ 197,278

8.31%

2004

2005

2006

2007

2008

Thereafter

Total

Fair Value
December 31,
2003

$ –

$ 18,000

$ 108,000

$180,000

$ 204,604

8.31%

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of the Managing
General Partner and the Partners of
Alliance Resource Partners, L.P.:

We have audited the accompanying consolidated balance sheets of Alliance Resource Partners, L.P. and subsidiaries (the
“Partnership”) as of December 31, 2004 and 2003, and the related consolidated statements of income, cash flows and Partners’ capital
(deficit) and comprehensive income for each of the three years in the period ended December 31, 2004. Our audits also included the finan-
cial statement schedule listed in the Index at Item 15. These financial statements and financial schedule are the responsibility of the
Partnership’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule
based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Partnership
as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended
December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such
financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents
fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effec-
tiveness of the Partnership’s internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal
Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated
March 15, 2005 expressed an unqualified opinion on management’s assessment of the effectiveness of the Partnership’s internal control
over financial reporting and an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Tulsa, Oklahoma
March 15, 2005

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2004 AND 2003
(In thousands, except unit data)

ASSETS
CURRENT ASSETS:

Cash and cash equivalents
Trade receivables, less allowance of $0 and $763 at December 31, 2004 and 2003
Other receivables
Marketable securities
Inventories
Advance royalties
Prepaid expenses and other assets

Total current assets

PROPERTY, PLANT AND EQUIPMENT, AT COST
LESS ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION

Total property, plant and equipment

OTHER ASSETS:

Advance royalties
Coal supply agreements, net
Other long-term assets
Total other assets

TOTAL ASSETS

LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable
Due to affiliates
Accrued taxes other than income taxes
Accrued payroll and related expenses
Accrued interest
Workers’ compensation and pneumoconiosis benefits
Other current liabilities
Current maturities, long-term debt

Total current liabilities

LONG-TERM LIABILITIES:

Long-term debt, excluding current maturities
Pneumoconiosis benefits
Workers’ compensation
Reclamation and mine closing
Due to affiliates
Other liabilities

Total long-term liabilities
Total liabilities

COMMITMENTS AND CONTINGENCIES

PARTNERS’ CAPITAL:

Common Unitholders 18,130,440 and 14,692,527 units outstanding, respectively
Subordinated Unitholder -0- and 3,211,266 units outstanding, respectively
General Partners’ deficit
Unrealized loss on marketable securities
Minimum pension liability
Total Partners’ capital

TOTAL LIABILITIES AND PARTNERS’ CAPITAL

See notes to consolidated financial statements.

December 31,

2004

2003

31,177
56,967
1,637
49,397
13,839
3,117
4,345
160,479

526,468
(292,900)
233,568

11,737
2,723
4,277
18,737
412,784

30,961
10,338
10,742
11,730
5,402
7,081
12,051
18,000
106,305

162,000
19,833
25,994
32,838
7,457
3,170
251,292
357,597

10,156
36,374
1,931
23,615
14,527
1,108
3,432
91,143

474,357
(251,567)
222,790

12,439
5,445
4,637
22,521
336,454

22,651
13,546
10,375
11,095
5,402
5,905
5,739

–

74,713

180,000
17,131
23,321
21,717
3,735
3,280
249,184
323,897

363,658

–

(303,295)
(54)
(5,122)
55,187
412,784

263,071
58,411
(305,034)
(102)
(3,789)
12,557
336,454

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003, AND 2002
(In thousands, except unit and per unit data)

SALES AND OPERATING REVENUES:

Coal sales
Transportation revenues
Other sales and operating revenues

Total revenues

EXPENSES:

Operating expenses
Transportation expenses
Outside purchases
General and administrative
Depreciation, depletion and amortization
Interest expense (net of interest income and interest
capitalized of $852, $545 and $1,353 for the
Partnership’s respective periods)
Net gain from insurance settlement

Total operating expenses

INCOME FROM OPERATIONS
OTHER INCOME

INCOME BEFORE INCOME TAXES

INCOME TAX EXPENSE (BENEFIT)

NET INCOME

ALLOCATION OF NET INCOME:

PORTION APPLICABLE TO WARRIOR COAL

EARNINGS (LOSS) PRIOR TO ITS ACQUISITION ON
FEBRUARY 14, 2003

PORTION APPLICABLE TO PARTNERS’ INTEREST

NET INCOME

GENERAL PARTNERS’ INTEREST IN NET INCOME (LOSS)
LIMITED PARTNERS’ INTEREST IN NET INCOME
BASIC NET INCOME PER LIMITED PARTNER UNIT
DILUTED NET INCOME PER LIMITED PARTNER UNIT
DISTRIBUTIONS PAID PER COMMON AND

SUBORDINATED UNIT

WEIGHTED AVERAGE NUMBER OF UNITS

OUTSTANDING—BASIC

WEIGHTED AVERAGE NUMBER OF UNITS

OUTSTANDING—DILUTED

See notes to consolidated financial statements.

Year Ended December 31,

2004

2003

2002

599,399
29,817
24,073
653,289

436,471
29,817
9,913
45,400
53,664

14,963
(15,217)
575,011

78,278
984

79,262

2,641

501,596
19,553
21,598
542,747

368,835
19,553
8,508
28,270
52,495

15,981

–

493,642

49,105
1,374

50,479

2,577

479,515
18,992
20,385
518,892

367,567
18,992
10,077
20,337
52,408

16,360
–
485,741

33,151
540

33,691

(1,094)

76,621

47,902

34,785

$
$
$
$

– $

76,621

3,324
73,297
4.09
3.98

2.4875

$
$
$
$

(666)
48,568

47,902

306
47,596
2.71
2.62

2.10

$
$
$
$

(1,504)
36,289

34,785

(778)
35,563
2.31
2.24

2.00

17,940,948

17,580,734

15,405,311

18,437,168

18,162,839

15,842,708

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003, AND 2002
(In thousands, except unit and per unit data)

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income
Adjustments to reconcile net income to net cash

provided by operating activities:
Depreciation, depletion and amortization
Reclamation and mine closings
Coal inventory adjustment to market
Other
Changes in operating assets and liabilities:

Trade receivables
Other receivables
Inventories
Advance royalties
Accounts payable
Due to affiliates
Accrued taxes other than income taxes
Accrued payroll and related benefits
Accrued pneumoconiosis benefits
Workers’ compensation
Other

Total net adjustments
Net cash provided by operating activities

CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property, plant and equipment
Purchase of Warrior Coal
Proceeds from sale of property, plant and equipment
Purchase of marketable securities
Proceeds from marketable securities
Proceeds from assumption of liability

Net cash used in investing activities

CASH FLOWS FROM FINANCING ACTIVITIES:

Proceeds from common unit offering to public
Cash contribution by General Partners
Payments on Warrior Coal revolving credit balance
Borrowings under revolving credit and working capital facilities
Payments under revolving credit and working capital facilities
Payments on long-term debt
Distributions to Partners

Net cash used in financing activities

NET CHANGE IN CASH AND CASH EQUIVALENTS
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
CASH AND CASH EQUIVALENTS AT END OF PERIOD

SUPPLEMENTAL CASH FLOW INFORMATION:

CASH PAID FOR:

Cash paid for interest
Cash paid to taxing authorities

NON-CASH ACTIVITY:

Market value of common units issued to Long-Term Incentive

Plan participants upon vesting

See notes to consolidated financial statements.

Year Ended December 31,

2004

2003

2002

76,621

47,902

34,785

53,664
1,622
488
255

(20,593)
294
200
(1,307)
8,678
14,194
367
635
2,702
3,849
3,386
68,434
145,055

(54,713)

–

687
(49,271)
23,537
2,112
(77,648)

–
3
–
–
–
–

(46,389)
(46,386)

21,021
10,156
31,177

15,229
2,150

$
$

13,680

$
$

52,495
1,341
687
(353)

(3,459)
(1,828)
(2,049)
2,227
(679)
9,978
2,270
1,091
1,064
4,002
(4,377)
62,410
110,312

(43,004)
(12,661)
913
(23,091)

–
–

(77,843)

53,927
9
(17,000)
31,600
(31,600)
(31,250)
(37,027)
(31,341)

1,128
9,028
10,156

15,960
2,681

52,408
1,365
48
(1,014)

(222)
(242)
(104)
(311)
(4,144)
14,080
1,936
1,348
1,452
2,568
(2,647)
66,521
101,306

(67,339)
–
323
–
10,085

–

(56,931)

–
–
–

66,400
(66,400)
(15,000)
(31,440)
(46,440)

(2,065)
11,093
9,028

17,294
–

$
$

–

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL (DEFICIT) AND COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003, AND 2002
(In thousands, except unit data)

Number of Limited
Partner Units

Common

Subordinated

Common

Subordinated

General
Partners’
(Deficit)

Unrealized Minimum
Pension
Liability

Gain
(Loss)

Total
Partners’
Capital
(Deficit)

Balance at January 1, 2002
Comprehensive income:
Net income (loss)
Unrealized loss
Minimum pension liability

Total comprehensive income

Distribution to Partners

8,982,780

6,422,531

$ 141,448

$ 110,935

$ (289,065)

(74)

(814)

$ (37,570)

–
–
–
–
–

20,737

14,826

(778)

–
–

20,737
(17,966)

14,826
(12,845)

–
–

(778)
(629)

–

(76)

–

(76)

–

–
–

(4,461)
(4,461)

–

34,785
(76)
(4,461)
30,248
(31,440)

Balance at December 31, 2002

8,982,780

6,422,531

144,219

112,916

(290,472)

(150)

(5,275)

(38,762)

Comprehensive income:

Net income
Unrealized gain
Minimum pension liability

Total comprehensive income

Issuance of units to public
General Partners contribution
Retirement of common units
contributed by Managing
General Partner

Subordinated units conversion

to common units
Warrior Coal purchase
Distribution to Partners

–
–
–
–

2,538,000

–

–
–
–
–
–
–

31,346
–
–

31,346
53,927

–

16,250

–
–

16,250

–
–

306

–
–

306

–
9

–
48
–
48
–
–

1,486
1,486

–
–

47,902
48
1,486
49,436
– 53,927
9
–

(39,518)

–

(890)

–

890

–

3,211,265

(3,211,265)

57,268

(57,268)

–

–
–

–

(22,799)

(13,487)

(15,026)
(741)

–
–
–

–
–
–
(15,026)
– (37,027)

Balance at December 31, 2003

14,692,527

3,211,266

263,071

58,411

(305,034)

(102)

(3,789)

12,557

Comprehensive income:

Net income
Unrealized gain
Minimum pension liability

Total comprehensive income

Issuance of units to Long-Term
Incentive Plan participants
upon vesting

General Partners contribution
Retirement of common units
contributed by Managing
General Partner

Distribution to Partners
Subordinated units conversion

–
–
–
–

60,685

12,612

3,324

–
–

60,685

12,612

3,324

–
48
–
48

–
–

(1,333)
(1,333)

76,621
48
(1,333)
75,336

231,126

–

–
–

13,680

–

–
–

–
3

–
–

13,680
3

(4,479)

–

–
–

(265)
(36,548)

–

(7,988)

265
(1,853)

–
–

–
(46,389)

to common units

3,211,266

(3,211,266)

63,035

(63,035)

–

Balance at December 31, 2004

18,130,440

–

$ 363,658

–

$ (303,295)

(54)

$ (5,122)

$ 55,187

See notes to consolidated financial statements.

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003, AND 2002

1. ORGANIZATION AND PRESENTATION

Alliance Resource Partners, L.P., a Delaware limited partnership (the “Partnership”) was formed in May 1999, to acquire, own and oper-
ate certain coal production and marketing assets of Alliance Resource Holdings, Inc., a Delaware corporation (“ARH”) (formerly known as
Alliance Coal Corporation), consisting of substantially all of ARH’s operating subsidiaries, but excluding ARH.

The Delaware limited partnerships, limited liability companies and corporation that comprise the Partnership’s subsidiaries are as
follows: Alliance Resource Partners, L.P., Alliance Resource Operating Partners, L.P. (the “Intermediate Partnership”), Alliance Coal, LLC (the
holding company for operations), Alliance Land, LLC, Alliance Properties, LLC, Alliance Service, Inc., Backbone Mountain, LLC, Excel Mining,
LLC, Gibson County Coal, LLC, Hopkins County Coal, LLC, MC Mining, LLC, Mettiki Coal, LLC, Mettiki Coal (WV), LLC, Mt. Vernon Transfer
Terminal, LLC, Pontiki Coal, LLC, Warrior Coal, LLC, Webster County Coal, LLC, and White County Coal, LLC.

The Partnership completed its initial public offering (the “IPO”) in August 1999, issuing 7,750,000 Common Units (“Common Units”)
at $19.00 per unit and received net proceeds of $133.7 million. Concurrently with the offering ARH contributed certain assets to the
Partnership in exchange for cash, 0.01% general partner interest in each of the Partnership and the Intermediate Partnership, the right to
receive incentive distributions as defined in the partnership agreement and the assumption of related indebtedness and 1,232,780 Common
Units and 6,422,531 Subordinated Units, that converted into Common Units during November 2004 and 2003 (Note 9), held by Alliance
Resource GP, LLC, a Delaware limited liability company and wholly-owned subsidiary of ARH (the “Special GP”). On February 14, 2003 and
March 14, 2003, the Partnership issued 2,250,000 and 288,000 additional Common Units at a public offering price of $22.51 per unit and
received net proceeds of $48.5 million and $6.2 million, respectively, before expenses of approximately $0.8 million, excluding under-
writers fees. In November 2003, 3,211,265 outstanding Subordinated Units were converted to Common Units in accordance with the part-
nership agreement. In November 2004, the remaining 3,211,266 subordinated units converted to Common Units and the Partnership issued
231,126 additional Common Units pursuant to the Long-Term Incentive Plan (Note 13). If at any time not more than twenty percent of the
then-issued and outstanding limited partner interests are held by persons other than the general partners and their affiliates, the managing
general partner will have the right to acquire all, but not less than all, of the remaining limited partner interest held by unaffiliated persons.
On February 14, 2003, the Partnership acquired Warrior Coal, LLC (“Warrior Coal”) (Note 3). Because the Warrior Coal acquisition was
between entities under common control, the acquisition was recorded at historical cost in a manner similar to that used in a pooling of
interests. Accordingly, the consolidated financial statements and accompanying notes of the Partnership as of December 31, 2002 and for
the year ended December 31, 2002 have been restated to reflect the combined historical results of operations, financial position and cash
flows of the Partnership and Warrior Coal. ARH Warrior Holdings, Inc. (“ARH Warrior Holdings”), a subsidiary of ARH, acquired Warrior
Coal on January 26, 2001.

The Partnership is managed by Alliance Resource Management GP, LLC, a Delaware limited liability company (the “Managing GP”),

which holds a 0.99% and 1.0001% managing general partner interest in the Partnership and the Intermediate Partnership, respectively.

The accompanying consolidated financial statements include the accounts and operations of the limited partnerships, limited
liability companies and corporation disclosed above and present the financial position as of December 31, 2004 and 2003 and the results
of their operations, cash flows and changes in partners’ capital (deficit) and comprehensive income for each of the three years in the
period ended December 31, 2004. All material intercompany transactions and accounts of the Partnership have been eliminated.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Estimates — The preparation of consolidated financial statements in conformity with generally accepted accounting principles
requires management to make estimates and assumptions that affect the reported amounts and disclosures in the consolidated financial
statements. Actual results could differ from those estimates.

Fair Value of Financial Instruments — The carrying amounts for accounts receivable, marketable securities, and accounts
payable approximate fair value because of the short maturity of those instruments. At December 31, 2004 and 2003, the estimated fair
value of long-term debt was approximately $197.3 million and $204.6 million, respectively. The fair value of long-term debt is based on
interest rates that management believes are currently available to the Partnership for issuance of debt with similar terms and remaining
maturities.

Cash and Cash Equivalents — Cash and cash equivalents include cash on hand and on deposit, including highly liquid investments

with maturities of three months or less.

Cash Management — The Partnership reclassified outstanding checks of $2,192,000 and $1,257,000 at December 31, 2004 and

2003, respectively, to accounts payable in the consolidated balance sheets.

Marketable Securities — The Partnership currently classifies all marketable securities as available-for-sale securities. At
December 31, 2004 and 2003, the cost of marketable securities are reported at fair value with unrealized gains and losses reported as a
component of Partners’ capital until realized. The Partnership has restricted investments of $1,816,000 and $1,809,000 at December 31,
2004 and 2003, respectively, which are included in other assets in the consolidated balance sheets. The restricted marketable securities
are held in escrow and secure reclamation bonds (Note 5).

Inventories — Coal inventories are stated at the lower of cost or market on a first-in, first-out basis. Supply inventories are stated

at the lower of cost or market on an average cost basis.

Property, Plant and Equipment — Additions and replacements constituting improvements are capitalized. Maintenance, repairs,
and minor replacements are expensed as incurred. Depreciation and amortization are computed principally on the straight-line method
based upon the estimated useful lives of the assets or the estimated life of each mine, whichever is less ranging from 2 to 13 years.
Depreciable lives for mining equipment and processing facilities range from 2 to 13 years. Depreciable lives for land and land improve-
ments and depletable lives for mineral rights range from 5 to 13 years. Depreciable lives for buildings, office equipment and improvements
range from 2 to 13 years. Gains or losses arising from retirements are included in current operations. Depletion of mineral rights is provid-
ed on the basis of tonnage mined in relation to estimated recoverable tonnage. At December 31, 2004 and 2003, land and mineral rights
include $2,030,000 and $2,178,000, respectively, representing the carrying value of coal reserves attributable to properties where the
Partnership is not currently engaged in mining operations or leasing to third parties, and therefore, the coal reserves are not currently being
depleted. Management believes that the carrying value of these reserves will be recovered.

Mine Development Costs — Mine development costs are capitalized and amortized over the estimated life of the mine.

Long-Lived Assets — The Partnership reviews the carrying value of long-lived assets and certain identifiable intangibles whenever
events or changes in circumstances indicate that the carrying amount may not be recoverable based upon estimated undiscounted future
cash flows. The amount of an impairment is measured by the difference between the carrying value and the fair value of the asset.

In June 2003, the Partnership idled the active surface mine at its Hopkins County Coal mining complex in response to soft market
demand. In October 2004, the surface mine was re-opened in response to incremental sales opportunities from existing customers as
well as strong market demand for Illinois Basin region coal. While the Hopkins County Coal mining complex was idled the Partnership eval-
uated the recoverability of the appropriate asset group and concluded that there was no impairment loss.

Advance Royalties — Rights to coal mineral leases are often acquired and/or maintained through advance royalty payments.
Management assesses the recoverability of royalty prepayments based on estimated future production and capitalizes these amounts
accordingly. Royalty prepayments expected to be recouped within one year are classified as a current asset. As mining occurs on those
leases, the royalty prepayments are included in the cost of mined coal. Royalty prepayments estimated to be nonrecoverable are expensed.
In March 2004, the Financial Accounting Standard Board (“FASB”) issued Emerging Issues Task Force Issue No. 04-2, Whether
Mineral Rights Are Tangible or Intangible Assets. In this Issue, the Task Force reached the consensus that mineral rights are tangible assets
and amended Statement of Financial Accounting Standards (“SFAS”) No. 141, Business Combinations, and SFAS No. 142, Goodwill and
Other Intangible Assets, which previously classified mineral rights as intangible assets. Consistent with other extractive industry entities,
the Partnership has historically included its related assets as tangible, therefore there was no material effect on the Partnership’s consol-
idated financial statements upon adoption.

Coal Supply Agreements — A portion of the acquisition costs from a business combination in 1996 was allocated to coal supply
agreements. This allocated cost is being amortized on the basis of coal shipped in relation to total coal to be supplied during the respec-
tive contract terms. The amortization periods end on various dates from September 2002 to December 2005. Accumulated amortization for
coal supply agreements was $35,740,000 and $33,018,000 at December 31, 2004 and 2003, respectively. The aggregate amortization
expense recognized for coal supply agreements was $2,722,000, $2,722,000 and $3,864,000 for the years ended December 31, 2004, 2003
and 2002, respectively. The estimated aggregate amortization expense for 2005 is approximately $2,723,000.

Reclamation and Mine Closing Costs — The liability for the estimated cost of future mine reclamation and closing procedures is
recorded on a present value basis when incurred and the associated cost is capitalized by increasing the carrying amount of the related
long-lived asset. Those costs relate to sealing portals at underground mines and to reclaiming the final pits and support acreage at surface
mines. Other costs common to both types of mining are related to removing or covering refuse piles and settling ponds, and dismantling
preparation plants, other facilities and roadway infrastructure.

Workers’ Compensation and Pneumoconiosis (“Black Lung”) Benefits — The Partnership is self-insured for workers’ compen-
sation benefits, including black lung benefits. The Partnership accrues a workers’ compensation liability for the estimated present value of
workers’ compensation and black lung benefits based on actuarial valuations.

Income Taxes — The Partnership is not a taxable entity for federal or state income tax purposes; the tax effect of its activities
accrues to the unitholders. Although publicly traded partnerships will, as a general rule, be taxed as corporations, the Partnership quali-
fies for an exemption because at least 90% of its income consists of qualifying income. Net income for financial statement purposes may
differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting
bases of assets and liabilities and the taxable income allocation requirements under the Partnership agreement. The Partnership’s sub-
sidiary, Alliance Service, Inc. (“Alliance Service”), is subject to federal and state income taxes. Prior to the Partnership’s acquisition of
Warrior Coal, the financial results of Warrior Coal were subject to federal and state income taxes. The federal and state income taxes asso-
ciated with Warrior Coal’s financial results from January 26, 2001, the date of ARH Warrior Holdings’ acquisition of Warrior Coal, to
February 14, 2003, the date of the Partnership’s acquisition of Warrior Coal, are included in income taxes. The Partnership’s tax counsel has
provided an opinion that the Partnership, the Intermediate Partnership and the holding company will each be treated as a partnership.
However, as is customary, no ruling has been or will be requested from the IRS regarding the Partnership's classification as a partnership
for federal income tax purposes.

Revenue Recognition — Revenues from coal sales are recognized when title passes to the customer as the coal is shipped. Some
coal supply agreements provide for price adjustments based on variations in quality characteristics of the coal shipped. In certain cases, a
customer’s analysis of the coal quality is binding and the results of the analysis are received on a delayed basis. In these cases, the
Partnership estimates the amount of the quality adjustment and adjusts the estimate to actual when the information is provided by the
customer. Historically such adjustments have not been material. Non-coal sales revenues primarily consist of rental and service fees
associated with agreements to host and operate a third-party coal synfuel facility and to assist with the coal synfuel marketing and other
related services. These non-coal sales revenues are recognized as the services are performed. Transportation revenues are recognized in
connection with the Partnership incurring the corresponding costs of transporting the coal to customers through third-party carriers since
the Partnership is directly reimbursed for these costs through customer billings.

Common Unit-Based Compensation — The Partnership accounts for the compensation expense of the non-vested restricted com-
mon units granted under the Long-Term Incentive Plan (Note 12) using the intrinsic value method prescribed in Accounting Principles Board
Opinion No. 25, Accounting for Stock Issued to Employees (“APB 25”) and the related Financial Accounting Standards Board Interpretation
No. 28, Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans (“FASB Interpretation No. 28”).
Compensation cost for the restricted common units is recorded on a pro-rata basis, as appropriate given the “cliff vesting” nature of the
grants, based upon the current market value of the Partnership’s common units at the end of each period.

Consistent with the disclosure requirements of SFAS No. 148, Accounting for Stock-Based Compensation Transition and Disclosure,
and amendment of SFAS No. 123, Accounting for Stock-Based Compensation, the following table provides pro forma results as if the fair
value-based method had been applied to all outstanding and non-vested awards, including Long-Term Incentive Plan units, in each period
presented (in thousands, except per unit data):

Year Ended December 31,

2004

2003

2002

Net income, as reported

76,621

47,902

34,785

Add: compensation expenses related to

Long-Term Incentive Plan units included in
reported net income

Deduct: compensation expense related to

Long-Term Incentive Plan units determined
under fair value method for all awards

Net income, pro forma

General partners’ interest in net income (loss),

pro forma

20,320

7,687

2,338

(3,915)

(3,632)

(2,257)

93,026

51,957

34,866

3,652

386

(777)

Limited partners’ interest in net income, pro forma

89,374

51,571

35,643

Earnings per limited partner unit:

Basic, as reported
Basic, pro forma
Diluted, as reported
Diluted, pro forma

$
$
$
$

4.09
4.98
3.98
4.85

$
$
$
$

2.71
2.93
2.62
2.84

$
$
$
$

2.31
2.38
2.24
2.32

The total accrued liability associated with the Long-Term Incentive Plan as of December 31, 2004 and 2003 was $10,013,000 and
$12,493,000, respectively, and is included in the current and long-term due to affiliates liabilities in the consolidated balance sheets. See
New Accounting Standards discussion below concerning the impact of SFAS No. 123R, Share-Based Payment, on accounting for the Long-
Term Incentive Plan.

Net Income Per Unit — Basic net income per limited partner unit is determined by dividing Limited Partners’ interest in net income
(Note 11), by the weighted average number of outstanding Common Units and Subordinated Units. Warrior Coal’s earnings (loss) prior to
the Partnership’s acquisition on February 14, 2003 was allocated entirely to the general partner. Diluted net income per unit is based on
the combined weighted average number of Common Units, Subordinated Units and common unit equivalents outstanding, which primarily
include restricted units granted under the Long-Term Incentive Plan (Note 13).

Segment Reporting — The Partnership has no reportable segments due to its operations consisting solely of producing and
marketing coal and providing rental and service fees associated with producing and marketing coal synfuel, which meets the aggregation
criteria of SFAS No. 131, Disclosures About Segments of an Enterprise and Related Information. The Partnership has disclosed major cus-
tomer sales information (Note 18). The Partnership’s geographic areas of operation are concentrated in the United States.

New Accounting Standards — In November 2004, the FASB issued SFAS No. 151, Inventory Costs. SFAS No. 151 is an amend-
ment of Accounting Research Bulletin (“ARB”) No. 43, chapter 4, paragraph 5 that deals with inventory pricing. SFAS No. 151 clarifies the
accounting for abnormal amounts of idle facility expenses, freight, handling costs, and spoilage. Under previous guidance, paragraph 5 of
ARB No. 43, chapter 4, items such as idle facility expense, excessive spoilage, double freight, and rehandling costs might be considered
to be so abnormal, under certain circumstances, as to require treatment as current period charges. This Statement eliminates the criteri-
on of “so abnormal” and requires that those items be recognized as current period charges. Also, SFAS No. 151 requires that allocation of
fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS No. 151 is effec-
tive for fiscal years beginning after June 15, 2005. The Partnership is analyzing the requirements of SFAS No. 151 and believes that its
adoption will not have any significant impact on the Partnership’s financial position, results of operations or cash flows.

In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment. SFAS No. 123R is a revision of SFAS No. 123, Accounting
for Stock Based Compensation, and supersedes APB 25. Among other items, SFAS No. 123R eliminates the use of APB 25 and the intrin-
sic value method of accounting, and requires companies to recognize the cost of employee services received in exchange for awards of
equity instruments, based on the grant date fair value of those awards, in the financial statements.

The effective date of SFAS No. 123R is the first reporting period beginning after June 15, 2005, and the Partnership expects to adopt
SFAS No. 123R effective July 1, 2005. SFAS No. 123R permits companies to adopt its requirements using either a “modified prospective”
method, or a “modified retrospective” method. Under the “modified prospective” method, compensation cost is recognized in the financial
statements beginning with the effective date, based on the requirements of SFAS No. 123R for all share-based payments granted after
that date, and based on the requirements of SFAS No. 123 for all unvested awards granted prior to the effective date of SFAS No. 123R.
Under the “modified retrospective” method, the requirements are the same as under the “modified prospective” method, but also permits
entities to restate financial statements of previous periods based on proforma disclosures made in accordance with SFAS No. 123. The
Partnership is currently evaluating the appropriate transition method.

As permitted by SFAS No. 123, the Partnership currently accounts for share based payments to employees using the APB No. 25 intrin-
sic method and related FASB Interpretation No. 28 based upon the current market value of the Partnership’s common units at the end of
each period. The Partnership has recorded compensation expense of $20,320,000, $7,687,000 and $2,338,000 for the years ended
December 31, 2004, 2003 and 2002, respectively. SFAS No. 123R does not permit entities to continue to use the intrinsic method, the
Partnership has not yet determined which model it will use to measure the fair value of restricted unit-based compensation upon the adop-
tion of SFAS No. 123R.

Reclassifications — Certain reclassifications have been made to the 2003 balance sheet presentation of receivables, pneumoco-

niosis benefits and workers’ compensation long-term liabilities to conform to the 2004 classifications.

3. ACQUISITIONS

Warrior Coal. On February 14, 2003, Warrior Coal was acquired from an affiliate, ARH Warrior Holdings, a subsidiary of ARH, pursuant
to an Amended and Restated Put and Call Option Agreement (“Put/Call Agreement”). Warrior Coal purchased the capital stock of Roberts
Bros. Coal Co., Inc., Warrior Coal Mining Company, Warrior Coal Corporation and certain assets of Christian Coal Corp. and Richland Mining
Co., Inc. in January 2001. The Managing GP originally declined the opportunity to purchase these assets as the Partnership had previous-
ly committed to major capital expenditures at two existing operations. As a condition to not exercising its right of first refusal, the
Partnership requested that ARH Warrior Holdings enter into a put and call arrangement for Warrior Coal. ARH Warrior Holdings and the
Partnership, with the approval of the Conflicts Committee of the Managing GP, entered into the Put/Call Agreement in January 2001.
Concurrently, ARH Warrior Holdings acquired Warrior Coal in January 2001 for $10.0 million.

The Put/Call Agreement preserved the opportunity for the Partnership to acquire Warrior Coal during a specified time period. Under
the terms of the Put/Call Agreement, ARH Warrior Holdings exercised its put option requiring the Partnership to purchase Warrior Coal at
a put option price of approximately $12.7 million.

The option provisions of the Put/Call Agreement were subject to certain conditions (unless otherwise waived), including, among
others, (a) the non-occurrence of a material adverse change in the business and financial condition of Warrior Coal, (b) the prohibition of
any dividends or other distributions to Warrior Coal’s shareholders, (c) the maintenance of Warrior Coal’s assets in good working condition,
(d) the prohibition on the sale of any equity interest in Warrior Coal except for the options contained in the Put/Call Agreement, and (e) the
prohibition on the sale or transfer of Warrior Coal’s assets except those made in the ordinary course of its business.

The Put/Call Agreement option prices reflected negotiated sale and purchase amounts that both parties determined would allow each
party to satisfy acceptable minimum investment returns in the event either the put or call options were exercised. In January 2001 and in
December 2002, the Partnership developed financial projections for Warrior Coal based on due diligence procedures it customarily per-
forms when considering the acquisition of a coal mine. The assumptions underlying the financial projections made by the Partnership for
Warrior Coal included, among others, (a) annual production levels ranging from 1.5 million to 1.8 million tons, (b) coal prices at or below
the then current coal prices and (c) a discount rate of 12 percent. Based on these financial projections, as of the date of the acquisition and
at December 31, 2002 and 2001, the Partner-ship believed that the fair value of Warrior Coal was equal to or greater than the put option
exercise price.

The put option price of $12.7 million was paid to ARH Warrior Holdings in accordance with the terms of the Put/Call Agreement. In
addition, the Partnership repaid Warrior Coal’s borrowings of $17.0 million under the revolving credit agreement between the Special GP
and Warrior Coal. The primary borrowings under the revolving credit agreement financed new infrastructure capital projects at Warrior Coal
that have contributed to improved productivity and significantly increased capacity. The Partnership funded the Warrior Coal acquisition
through a portion of the proceeds received from the issuance of 2,250,000 Common Units (Note 1). Because the Warrior Coal acquisition
was between entities under common control, it has been accounted for at historical cost in a manner similar to that used in a pooling of
interests.

Under the terms of the Put/Call Agreement, the Partnership assumed certain other obligations, including a mineral lease and sublease
with SGP Land, LLC (“SGP Land”), a subsidiary of the Special GP, covering coal reserves that have been and will continue to be mined by
Warrior Coal. The terms and conditions of the mineral lease and sub-lease remained unchanged (Note 16).

Lodestar. On July 15, 2003, Hopkins County Coal, LLC (“Hopkins County Coal”) executed an Asset Purchase Agreement with Lodestar
Energy, Inc. (“Lodestar”), a coal company operating in Chapter 7 bankruptcy proceedings. Concurrently, Hopkins County Coal entered into
various other agreements (collectively, the Asset Purchase Agreement and the various other agreements are referred to as the “Lodestar
Agreements”) with several parties, including the Kentucky Environmental and Public Protection Cabinet (“Cabinet”) and Frontier Insurance
Company (“Frontier”). Closing of the Lodestar Agreements was subject to the resolution of numerous contingencies and/or conditions.
Under the terms of the relevant Lodestar Agreements, Hopkins County Coal principally acquired a mining pit, created by Lodestar’s mining
activities. The mining pit will be used for refuse disposal by the Partnership’s Webster County Coal, LLC’s Dotiki mine. The purchase price
included a nominal monetary amount and the assumption of remedial reclamation activities under the various mining permits acquired by
Hopkins County Coal from Lodestar. The Cabinet accepted these remedial activities in lieu of certain solid waste closure requirements
applicable to residual landfills. Hopkins County Coal also received $2.1 million from Frontier in exchange for the assumption of the
remedial activities associated with the mining pit. As a result of closing the Lodestar Agreements on June 2, 2004, Hopkins County Coal
recorded the fair value of the asset retirement obligation of approximately $4.1 million with a corresponding asset that was reduced by the
$2.1 million of cash received.

Elk Creek – Tunnel Ridge. On October 21, 2004, the Partnership announced an agreement, subject to finalization of definitive agree-
ments, to enter into two separate coal leases, the Elk Creek reserves (“Elk Creek”), which are located in Hopkins County, Kentucky, and the
Tunnel Ridge reserves (“Tunnel Ridge”), which are located in Ohio County, West Virginia and Washington County, Pennsylvania. These leas-
es are estimated to contain approximately 100 million tons of high-sulfur coal reserves. The lessor for both leases is the Special GP. The
Partnership also announced plans to immediately begin the development process for these properties, which includes obtaining the nec-
essary mining permits and securing sufficient coal sales commitments to justify the capital investment needed to bring these properties
into production.

The Elk Creek reserve area encompasses approximately 9,000 acres and is contiguous to the Partnership’s Hopkins County Coal com-
plex. The Elk Creek coal reserves are currently estimated to include approximately 30 million tons of high-sulfur coal. The Elk Creek mine
will be an underground mining complex, mining the West Kentucky No. 9 and No. 11 coal seams. It will utilize continuous mining units and
employ room-and-pillar mining techniques. The mine intends to use the existing coal handling and other surface facilities owned by Hopkins
County Coal. The Partnership anticipates that the Elk Creek complex will employ as many as 250 individuals and produce up to 3.2 million
tons of coal annually. The Partnership is estimating total capital expenditures to develop Elk Creek to be approximately $65.0 million. Coal
supply commitments are currently being pursued. Construction of the Elk Creek mining complex began in the first quarter of 2005. The
Partnership expects to fund these capital expenditures with available cash and marketable securities on hand, future cash generated from
operations and/or borrowings available under the revolving credit facility.

In December 2000, Hopkins County Coal entered into an option agreement to lease and/or sublease the Elk Creek reserves from the
Partnership's Special GP. Under the terms of the option to lease and sublease, Hopkins County Coal paid an option fee of $645,000 during
the year ended December 31, 2000, and paid option fees of $684,000 during each of the years ended December 31, 2001, 2002 and 2004.
The 2003 option fee of $684,000 was paid in January 2004. Upon exercise of the option to lease or sublease, Hopkins County Coal is obli-
gated to make an additional five annual advance minimum royalty payments of $684,000 per year, which royalty is fully recoupable against
earned royalties. The earned royalty rate under the lease and/or sublease is $0.25 per ton.

In January 2005, the Partnership acquired 100% of the limited liability company member interests of Tunnel Ridge, LLC for approxi-
mately $500,000 and the assumption of reclamation liabilities from Alliance Resource Holdings, Inc., a company owned by management of
the Partnership. Tunnel Ridge, LLC controls through a coal lease agreement with the Special GP an estimated 70 million tons of high-
sulfur coal in the Pittsburgh No. 8 coal seam. The Tunnel Ridge reserve area encompasses approximately 50,571 acres of land located in
Ohio County, West Virginia and Washington County, Pennsylvania. Under the terms of the coal lease, beginning on January 1, 2005, Tunnel
Ridge, LLC shall pay the Special GP an advance minimum royalty of $3.0 million per year. The advance royalty payments will be fully
recoupable against earned royalties. The earned royalty rate under the coal lease is the greater of $0.75 per ton or 3.0% of theper ton gross
sales price f.o.b. barge. The term of the coal lease is the earlier of 30 years or until exhaustion of all mineable andmerchantable coal. The
Partnership has termination rights after the initial four years of the coal lease.

Tunnel Ridge, LLC also controls, under a separate lease agreement with the Special GP, the rights to approximately 900 acres of sur-
face land and other tangible assets. Under the terms of the lease agreement, Tunnel Ridge, LLC shall pay to the Special GP an annual lease
payment of $240,000 beginning January 1, 2005. The lease agreement has an initial term of four years, which may be extended by Tunnel
Ridge, LLC, at the same annual lease payment rate, to be consistent with the term of the coal lease.

The Elk Creek and Tunnel Ridge transactions described above are related-party transactions and, as such, were reviewed by the Board
of Directors of the Partnership’s Managing GP and Conflicts Committee. Based upon these reviews, it was determined that these transac-
tions reflect market-clearing terms and conditions customary in the coal industry. As a result, the Board of Directors of the Partnership’s
Managing GP and its Conflicts Committee approved the Elk Creek and Tunnel Ridge transactions as fair and reasonable to the Partnership
and its limited partners.

4. MINE FIRE INCIDENTS

Dotiki Mine Fire. On February 11, 2004, Webster County Coal, LLC’s (“Webster County Coal”) Dotiki mine was temporarily idled for a
period of twenty-seven calendar days following the occurrence of a mine fire that originated with a diesel supply tractor (the “Dotiki Fire
Incident”). As a result of the firefighting efforts of the Mine Safety and Health Administration, Kentucky Department of Mines and
Minerals, and Webster County Coal personnel, Dotiki successfully extinguished the fire and totally isolated the affected area of the mine
behind permanent barriers. Initial production resumed on March 8, 2004. For the Dotiki Fire Incident, the Partnership had commercial
property insurance that provided coverage for damage to property destroyed, interruption of business operations, including profit recovery,
and expenditures incurred to minimize the period and total cost of disruption to operations.

On September 10, 2004, the Partnership filed a third and final proof of loss with the applicable insurance underwriters reflecting a
settlement (the “Dotiki Settlement”) of all expenses, losses and claims incurred by Webster County Coal and other affiliates arising from
or in connection with the Dotiki Fire Incident (the “Dotiki Insurance Claim”) in the aggregate amount of $27.0 million, inclusive of a $1.0
million self-retention, a $2.5 million deductible (collectively, the “Dotiki Insurance Deductibles”) and 10% co-insurance (the “2004

Co-Insurance”). The 2004 Insurance Deductibles and 2004 Co-Insurance were allocated on a pro-rata basis to each of the three areas of
insurance recoveries discussed below. In addition, the accounting for two net partial advance payments in the aggregate amount of $8.1
million and the final net payment of $13.05 million, exclusive of the 2004 Insurance Deductible and 2004 Co-Insurance, were subject to the
accounting methodology described below. Specifically, the Partnership evaluated and accounted for the insurance recoveries in the follow-
ing areas:
1.

Expenses incurred as a result of the fire – The Partnership incurred extra expenses, expediting expenses, and other costs
associated with extinguishing the fire in an aggregate amount of approximately $7.1 million. With application of $5.6 million
of the insurance recovery proceeds, the Partnership recorded net expenses of approximately $1.5 million.
Damage to Dotiki mine property – The Partnership incurred damage to Dotiki’s mine property (exclusive of any amounts
relating to matters discussed in 1. above) of approximately $1.2 million, which property had a net book value of $138,000.
Based on discussions with the underwriters culminating in the Dotiki Settlement, the Partnership recorded a net gain of
approximately $785,000, reflecting the amount that the allocated insurance proceeds exceeded the net book value of the
damaged property.
Dotiki mine business interruption costs and extra expense – Based on the negotiations with the underwriters leading to the
Dotiki Settlement, the Partnership recorded a net gain of approximately $14.4 million for the recovery of business interruption
costs and extra expenses stemming from the Dotiki Fire Incident. This net gain amount reflects an offset of approximately
$200,000 for professional services expenses incurred in resolving the business interruption portion of the Dotiki Settlement.

Pursuant to the accounting methodology described above, the Partnership recorded (a) an offset to operating expenses of approxi-
mately $5.9 million and (b) a combined net gain of approximately $15.2 million for damage to property destroyed, interruption of business
operations (including profit recovery), and extra expenses incurred to minimize the period and total cost of disruption to operations asso-
ciated with the Dotiki Fire Incident.

MC Mining Mine Fire. On December 26, 2004, MC Mining, LLC’s (“MC Mining”) Excel No. 3 mine was temporarily idled following the
occurrence of a mine fire (the “MC Mining Fire Incident”). The fire was discovered by mine personnel near the bottom of the Excel No. 3
mine slope late in the evening of December 25, 2004.

Under a firefighting plan developed by MC Mining, in cooperation with mine emergency response teams from the Mine Safety and
Health Administration and Kentucky Office of Mine Safety and Licensing, the four portals at the Excel No. 3 mine were capped to deprive
the fire of oxygen. A series of boreholes were then drilled into the fire area to further suppress the fire. As a result of these efforts, the
mine atmosphere was rendered substantially inert, or without oxygen, and the Excel No. 3 mine fire was effectively suppressed. MC Mining
then began construction of temporary and permanent barriers designed to completely isolate the mine fire area. When construction of the
permanent barriers was completed, MC Mining began efforts to repair and rehabilitate the Excel No. 3 mine infrastructure. On February
21, 2005, the repair and rehabilitation efforts had progressed sufficiently to allow initial resumption of production. The Partnership antici-
pates that MC Mining may return to full production by the end of the first quarter of 2005, but we cannot assure that our ability to produce
will not continue to be adversely impacted by the MC Mining Fire Incident for a period of time. The boreholes continue to be used to
monitor the mine atmosphere and to inject nitrogen into the area of the fire now isolated behind the permanent barriers.

The Partnership maintains commercial property (including business interruption) insurance policies, which are renewed annually in
September and provide for self-retention and various applicable deductibles, including certain monetary and/or time element forms of
deductibles, (collectively the “2005 Deductibles”) and 10% co-insurance (“2005 Co-Insurance”), however, the Partnership cannot give any
assurances as to the eventual timing or amount of any recovery of proceeds under these policies. The Partnership has made an initial esti-
mate of certain costs primarily associated with activities relating to the suppression of the fire and the resumption of operations. Operating
expenses for the 2004 fourth quarter increased by $4.1 million reflecting an initial estimate of certain minimum costs attributable to the
MC Mining Fire Incident that are not reimbursable under the Partnership’s insurance policies due to the application of the 2005 Deductibles
and 2005 Co-Insurance. An increase in the amount of such costs is possible, but is not currently subject to a reasonable estimate at this
time. In addition to these initial cost estimates, the Partnership expects to incur additional out-of-pocket costs that will generally fall into
the categories of extra expenses, expediting expenses and other areas of coverage under the commercial insurance policies. These future

out-of-pocket costs, which are not currently subject to reasonable estimation, will be expensed as incurred. The related estimated insur-
ance recovery of these costs will be recorded, net of the 2005 Deductibles and 2005 Co-Insurance, as the Partnership determines that such
recoveries are probable. Any recovery under the insurance policies of business interruption proceeds attributable to amounts in excess of
actual costs incurred will be recorded as gains when the claims are settled with the insurance underwriters.

5. MARKETABLE SECURITIES

Marketable securities include or have historically included Federal home loan discount notes, bankers acceptances, certificates of
deposits and equity securities. At December 31, 2004 and 2003, the cost of the bankers acceptances and certificates of deposit approxi-
mated fair value and no effect of unrealized gains (losses) is reflected in Partners’ capital. The Federal home loan discount notes and
equity securities had a cumulative unrealized loss reflected in Partners’ capital of $54,000 and $102,000 at December 31, 2004 and 2003,
respectively.

Marketable securities consist of the following at December 31, (in thousands):

Federal home loan discount notes
Bankers acceptances
Certificates of deposit
Equity securities

Total unrestricted marketable securities

Cash and cash equivalents

Total restricted marketable securities (included

in other long-term assets)

INVENTORIES

Inventories consist of the following at December 31, (in thousands):

Coal
Supplies

2004

2003

39,414
9,983
–
–
49,397

1,816

2004

4,822
9,017
13,839

–
–

23,091
524
23,615

1,809

2003

6,186
8,341
14,527

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consists of the following at December 31, (in thousands):

Mining equipment and processing facilities
Land and mineral rights
Buildings, office equipment and improvements
Construction in progress

Less accumulated depreciation, depletion and amortization

LONG-TERM DEBT

Long-term debt consists of the following at December 31, (in thousands):

Senior notes
Less current maturities

2004

2003

448,571
22,281
46,281
9,335
526,468
(292,900)
233,568

411,070
20,705
36,786
5,796
474,357
(251,567)
222,790

2004

2003

180,000
(18,000)
162,000

180,000
–
180,000

The Intermediate Partnership has $180 million principal amount of 8.31% senior notes due August 20, 2014, payable in ten equal
annual installments of $18 million beginning in August 2005 with interest payable semiannually. On August 22, 2003, the Intermediate
Partnership completed a $85 million revolving credit facility which expires September 30, 2006. The revolving credit facility replaced a $100
million credit facility that would have expired August 2004. The Partnership paid in full all amounts outstanding under the original credit
facility with borrowings of $20 million under the new revolving credit agreement. The interest rate on the revolving credit facility is based
on either the (i) London Interbank Offered Rate or (ii) the “Base Rate,” which is equal to the greater of the JPMorgan Chase Prime Rate or
the Federal Funds Rate plus 1/2 of 1%, plus, in either case, an applicable margin. The Partnership incurred certain costs aggregating $1.2
million associated with the revolving credit facility. These costs have been deferred and are being amortized as a component of interest
expense over the term of the revolving credit facility. The Partnership had no borrowings outstanding under the revolving credit facility at
December 31, 2004. Letters of credit can be issued under the revolving credit facility not to exceed $30 million; outstanding letters of cred-
it reduce amounts available under the revolving credit facility. At December 31, 2004, the Partnership had letters of credit of $9.0 million
outstanding under the revolving credit facility to secure the Partnership’s obligations for reclamation liabilities and workers’ compensation
benefits.

The senior notes and revolving credit facility are guaranteed by all of the subsidiaries of the Intermediate Partnership. The senior
notes and revolving credit facility contain various restrictive and affirmative covenants, including the amount of distributions by the
Intermediate Partnership and the incurrence of other debt exceeding $35 million. The senior note restrictions on distributions are consis-
tent with the Partnership Agreement and the credit facility limit borrowings to fund distributions to $25,000,000. The Partnership was in
compliance with the covenants of both the revolving credit facility and senior notes at December 31, 2004.

The Partnership previously entered into and has maintained agreements with two banks to provide additional letters of credit in an
aggregate amount of $25.0 million to maintain surety bonds to secure its obligations for reclamation liabilities and workers’ compensation
benefits. At December 31, 2004, the Partnership had $22.2 million in letters of credit outstanding under these agreements. The Special GP
guarantees the letters of credit (Note 16).

Aggregate maturities of long-term debt are payable as follows (in thousands):

Year Ending December 31,

2005
2006
2007
2008
2009
Thereafter

18,000
18,000
18,000
18,000
18,000
90,000
180,000

9. DISTRIBUTIONS OF AVAILABLE CASH AND CONVERSION OF SUBORDINATED UNITS

The Partnership Agreement provides for the conversion of the Subordinated Units into Common Units after meeting certain financial
tests. The Partnership satisfied, in two stages, the financial tests that resulted in the Subordinated Units being converted into Common
Units. First, the Partnership satisfied certain financial tests that provided for the early conversion of one-half of the Subordinated Units (i.e.
3,211,265 Subordinated Units) to Common units in September 2003. Second, the Partnership satisfied the final conversion financial tests
for converting the remaining Subordinated Units (i.e. 3,211,266 Subordinated Units) to Common Units in September 2004. The Board of
Directors (and its Conflicts Committee) for the Managing GP approved management's determination that the early conversion financial tests
and the final conversion financial tests were met. As a result, one-half of the Subordinated Units converted into Common Units on November
15, 2003 and the remaining one-half of the Subordinated Units converted into Common Units on November 2, 2004.

The Partnership will distribute 100% of its available cash within 45 days after the end of each quarter to unitholders of record and
to the General Partners. Available cash is generally defined as all cash and cash equivalents of the Partnership on hand at the end of each
quarter less reserves established by the Managing GP in its reasonable discretion for future cash requirements. These reserves are retained
to provide for the conduct of the Partnership’s business, the payment of debt principal and interest and to provide funds for future
distributions.

As quarterly distributions of available cash exceed the minimum quarterly distribution (“MQD”) and target distributions levels as
established in the Partnership Agreement, the Managing GP receives distributions based on specified increasing percentages of the avail-
able cash that exceed the MQD and the target distribution levels. The Partnership Agreement defines the MQD as $0.50 per unit ($2.00
per unit on an annual basis). The target distribution levels are based on the amounts of available cash from the Partnership’s operating sur-
plus distributed for a given quarter that exceed the MQD and common unit arrearages, if any.

Under the quarterly incentive distribution provisions of the partnership agreement, the Managing GP is entitled to receive 15% of the
amount the Partnership distributes in excess of $0.55 per unit, 25% of the amount the Partnership distributes in excess of $0.625 per unit,
and 50% of the amount the Partnership distributes in excess of $0.75 per unit. During 2004 the Partnership allocated to the Managing GP
incentive distributions of $1,828,000. There were no incentive distributions allocated to the Managing GP during the years ended December
31, 2003 and 2002. The following table summarizes the quarterly per unit distribution paid during the respective quarter.

First Quarter
Second Quarter
Third Quarter
Fourth Quarter

2004

$0.5625
$0.6250
$0.6500
$0.6500

Year

2003

$0.5250
$0.5250
$0.5250
$0.5250

2002

$0.5000
$0.5000
$0.5000
$0.5000

On January 27, 2005, the Partnership declared a quarterly distribution of $0.75 per unit, totaling approximately $14,797,000 (which
includes the Managing GP’s portion of incentive distributions), payable on February 14, 2005, to all unitholders of record on February 7, 2005.

10.

INCOME TAXES

The Partnership’s subsidiary, Alliance Service, is subject to federal and state income taxes. In conjunction with a decision to relocate
the coal synfuel facility from Hopkins County Coal to Warrior Coal, agreements for a portion of the services provided to the coal synfuel
producer were assigned to Alliance Service in December 2002. Alliance Service has no temporary differences between the financial report-
ing basis and the tax basis of its assets and liabilities. Prior to the Partnership’s acquisition of Warrior Coal, the financial results of Warrior
Coal were subject to federal and state income taxes. The federal and state income taxes associated with Warrior Coal’s financial results
prior to the Partnership’s acquisition on February 14, 2003, are included in income taxes. Components of income tax expense
(benefit) are as follows (in thousands):

Year Ended December 31,

2004

2003

2002

Current:

Federal
State

Deferred:

Federal
State

2,089
552
2,641

–
–
–

Income tax expense (benefit)

2,641

1,516
431
1,947

550
80
630
2,577

310
45
355

(1,269)
(180)
(1,449)
(1,094)

Reconciliations from the provision for income taxes at the U.S. federal statutory rate to the effective tax rate for the provision for

income taxes are as follows (in thousands):

Year Ended December 31,

2004

2003

2002

Income taxes at statutory rate

27,742

17,668

11,792

Less: Income taxes at statutory rate on

Partnership income not subject to income taxes

(25,409)

(15,855)

(12,606)

Increase/(decrease) resulting from:

Depletion
State taxes, net of federal income tax benefit
Deferred tax assets retained by

ARH Warrior Holdings

Other

–

333

–

(25)

–

313

413
38

(114)
(136)

–
(30)

Income tax expense (benefit)

2,641

2,577

(1,094)

11. NET INCOME PER LIMITED PARTNER UNIT

A reconciliation of net income and weighted average units used in computing basic and diluted earnings per unit is as follows (in

thousands, except per unit data):

Net income
Adjustments:

Managing General Partner’s incentive distributions
General Partners’ 2% equity ownership
Portion applicable to Warrior loss prior to its

acquisition on February 14, 2003

Limited partners’ interest in net income

Weighted average limited partner units - basic

Year Ended December 31,

2004

2003

2002

76,621

47,902

34,785

(1,828)
(1,496)

–

73,297

17,941

–

(972)

666

47,596

17,581

–

(726)

1,504

35,563

15,405

Basic net income per limited partner unit

4.09

2.71

2.31

Weighted average limited partner units—basic
Units contingently issuable:

Restricted units for Long-Term Incentive Plan
Directors’ compensation units deferred
Supplemental Executive Retirement Plan

Weighted average limited partner units, assuming

dilutive effect of restricted units

17,941

17,581

15,405

434
16
46

527
16
39

390
13
35

18,437

18,163

15,843

Diluted net income per limited partner unit

3.98

2.62

2.24

Partnership’s net income is allocated to the general partners and limited partners in accordance with their respective partnership per-
centages, after giving effect to any priority income allocations for incentive distributions (Note 9), if any, to the Partnership’s Managing GP,
the holder of the incentive distribution rights pursuant to the Partnership Agreement, which are declared and paid following the close of
each quarter. Warrior Coal’s loss prior to its acquisition on February 14, 2003 was allocated to the general partners.

The Managing GP is entitled to receive incentive distributions if the amount the Partnership distributes with respect to any quarter
exceeds levels specified in the Partnership Agreement. Under the quarterly incentive distribution provisions of the Partnership Agreement,
generally, the Managing GP is entitled to receive 15% of the amount the Partnership distributes in excess of $0.55 per unit, 25% of the
amount the Partnership distributes in excess of $0.625 per unit and 50% of the amount the Partnership distributes in excess of $0.75
per unit.

12. EMPLOYEE BENEFIT PLANS

Defined Contribution Plans — The Partnership’s employees currently participate in a defined contribution profit sharing and sav-
ings plan sponsored by the Partnership. This plan covers substantially all full-time employees. Plan participants may elect to make volun-
tary contributions to this plan up to a specified amount of their compensation. The Partnership makes matching contributions based on a
percent of an employee’s eligible compensation and for certain subsidiaries makes an additional nonmatching contribution also based on
an employee’s eligible compensation. Additionally, the Partnership contributes a defined percentage of eligible earnings for certain em-
ployees not covered by the defined benefit plan described below. The Partnership’s expense for its plan was approximately $3,267,000,
$2,975,000 and $2,959,000 for the years ended December 31, 2004, 2003 and 2002, respectively.

Defined Benefit Plans — Certain employees at the mining operations participate in a defined benefit plan (the “Pension Plan”)

sponsored by the Partnership. The benefit formula is a fixed dollar unit based on years of service.

The following sets forth changes in benefit obligations and plan assets for the years ended December 31, 2004 and 2003 and the
funded status of the Pension Plan reconciled with amounts reported in the Partnership’s consolidated financial statements at December
31, 2004 and 2003, respectively (dollars in thousands):

2004

2003

Change in benefit obligations:

Benefit obligations at beginning of year
Service cost
Interest cost
Actuarial loss
Benefits paid
Benefit obligation at end of year

Change in plan assets:

Fair value of plan assets at beginning of year
Employer contribution
Actual return on plan assets
Benefits paid
Fair value of plan assets at end of year
Funded status
Unrecognized prior service cost
Unrecognized actuarial loss
Net amount recognized

Amounts recognized in statement of financial position:

Accrued benefit liability
Intangible asset
Accumulated other comprehensive income

Net amount recognized

Weighted-average assumptions as of December 31:

Discount rate

Weighted-average assumptions used to determine net

periodic benefit cost for the year ended December 31:
Discount rate
Expected return on plan assets

Weighted-average asset allocations as of December 31:

Equity securities
Fixed income securities
Cash and cash equivalents

22,948
2,821
1,427
2,180
(270)
29,106

21,185

–

2,392
(270)
23,307
(5,799)
90
5,122
(587)

(5,799)
90
5,122
(587)

18,077
2,502
1,215
1,367
(213)
22,948

12,432
5,397
3,569
(213)
21,185
(1,763)
139
3,789
2,165

(1,763)
139
3,789
2,165

5.75%

6.25%

6.25%
8.00%

88%
11%
1%
100%

6.75%
8.00%

86%
13%
1%
100%

Components of net periodic benefit cost:

Service cost
Interest cost
Expected return on plan assets
Prior service cost
Net loss

Net periodic benefit cost
Effect on minimum pension liability

2004

2003

2002

$
$

2,821
1,427
(1,686)
48
141
2,751
(1,333)

$
$

2,502
1,215
(1,115)
48
399
3,049
(1,486)

$
$

2,249
952
(1,050)
48
–

2,199
4,461

Estimated future benefit payments as of December 31, 2004 are as follows (in thousands):

Year Ending December 31,

2005
2006
2007
2008
2009
2010-2014

460
634
806
998
1,219
10,322
14,439

The actuarial loss component of the change in benefit obligations for 2004 and 2003 was primarily attributable to reductions in the

discount rate assumptions. The Partnership expects to contribute $2,700,000 to the Pension Plan in 2005.

The Compensation Committee (“Compensation Committee”) of the Board of Directors of the Managing GP maintains a Funding and
Investment Policy Statement (“Policy Statement”) for the Pension Plan. The Policy Statement provides that the assets of the Pension Plan
be invested in a diversified mix of domestic equity securities and international equity securities, domestic fixed income securities and cash
equivalents with the goal of ensuring that the Pension Plan assets provide sufficient resources to meet or exceed benefit obligations.
Investment options, which may be through mutual funds, collective funds, or direct investment in individual stock, bonds or cash equiva-
lent investments, include (a) money market accounts, (b) U.S. Government bonds, (c) corporate bonds, (d) large, mid, and small capitaliza-
tion stocks, and (e) international stocks. The Policy Statement imposes the following limitations, subject to exceptions authorized by the
Compensation Committee under unusual market conditions: the maximum investment in any one stock should not exceed 10% of the total
stock portfolio, the maximum investment in any one industry should not exceed 30% of the total stock portfolio, and the average credit
quality of the bond portfolio should be at least AA with a maximum amount of non-investment grade debt of 10%. The Policy Statement’s
current asset allocation guidelines are as follows:

Domestic stocks
Foreign stocks
Fixed income/cash

Percentage of Total Portfolio

Minimum
50%
0%
5%

Target
70%
10%
20%

Maximum
90%
20%
40%

The expected long-term rate of return assumption is developed based on input from an independent investment manager, including
its review of asset class return, expectations by economists, and an independent actuary. The Partnership’s advisors base the projected
returns on broad equity and bond indices. The Pension Plan’s expected long-term rate of return is based on an asset allocation assumption
of 80.0% with equity manager, with an expected long-term rate of return of 10.4%, and 20.0% with fixed income managers, with an expect-
ed long-term rate of return of 5.4%. The Pension Plan was established effective January 1, 1997 and the Partnership’s initial contribution
to the Pension Plan was made in 1998.

13. COMPENSATION PLANS

Effective January 1, 2000, the Managing GP adopted the Long-Term Incentive Plan (the “LTIP”) for certain employees and directors of
the Managing GP and its affiliates who perform services for the Partnership. Annual grant levels and vesting provisions for designated par-
ticipants are recommended by the President and Chief Executive Officer of the Managing GP, subject to the review and approval of the
Compensation Committee. Grants are made either of restricted units, which are “phantom” units that entitle the grantee to receive a
Common Unit or an equivalent amount of cash upon the vesting of the phantom unit, or options to purchase Common Units. Common Units
to be delivered upon the vesting of restricted units or to be issued upon exercise of a unit option will be acquired by the Managing GP in
the open market at a price equal to the then prevailing price, or directly from ARH or any other third party, including units newly issued by
the Partnership, units already owned by the Managing GP, or any combination of the foregoing. The Partnership agreement provides that
the Managing GP be reimbursed for all costs incurred in acquiring these Common Units or in paying cash in lieu of Common Units upon
vesting of the restricted units.

The aggregate number of units reserved for issuance under the LTIP is 600,000. Effective January 1, 2004, the Compensation
Committee approved an amendment to the LTIP clarifying that if an award is paid or settled in cash rather than through the delivery of units,
then the units granted by such award shall be “reloaded” with respect to which options and restricted units may be granted under the LTIP
in the future. In November 2004, the initial LTIP vesting requirements were met when the Partnership satisfied the final conversion finan-
cial tests for converting the remaining Subordinated Units into Common Units (Note 9). As a result, LTIP grants of 385,210 units vested in
November 2004. The Partnership issued 231,126 Common Units to participants and paid cash to or on behalf of participants for the equiv-
alent of 154,084 units to satisfy personal income tax obligations. During 2004 and 2003 the Compensation Committee approved grants of
102,785 and 141,205 restricted units, respectively, which will vest December 31, 2006 and September 30, 2005, subject to the satisfaction
of certain financial tests. As of December 31, 2004, 2,765 restricted units outstanding LTIP grants have been forfeited. During 2004, 2003
and 2002, the Managing GP billed the Partnership approximately $20,320,000, $7,687,000, and $2,338,000, respectively, attributable to the
LTIP. Effective January 1, 2005, the Compensation Committee approved additional grants of 57,195 restricted units, which will vest January
1, 2008, subject to the satisfaction of certain financial tests. As of December 31, 2004 there were 127,649 Common Units available for
future issuance under the LTIP assuming all grants currently issued and outstanding for calendar year 2003, 2004 and 2005 are settled with
common units.

Effective January 1, 1997, the Managing GP adopted a Supplemental Executive Retirement Plan (the “SERP”) for certain officers and
key employees. The purpose of the SERP is to enhance the Partnership’s ability to retain specific officers and key employees, by providing
them with the deferred compensation benefits contained in the SERP. The intent of the SERP is to provide each participant with retirement
benefits that are comparable in value to those of similar retirement programs administered by other companies, as well as to align each
participant’s supplemental benefits under the SERP with the interests of the Partnership’s unitholders. All allocations made to participants
under the SERP are made in the form of “phantom” units. The SERP is administered by the Compensation Committee. The Managing GP is
able to amend or terminate the plan at any time. The Managing GP is entitled to reimbursement by the Partnership for its costs incurred
under the SERP. During 2004, 2003 and 2002, the Managing GP billed the Partnership approximately $2,099,000, $626,000, and $64,000,
respectively, attributable to the SERP. The increases from 2003 to 2004 and 2002 to 2003 are attributable to the increased market value of
the Partnership’s Common Units. The total accrued liability associated with the SERP plan as of December 31, 2004 and 2003 was
$3,657,000 and $1,558,000, respectively, and is included in the long-term due to affiliates liability in the consolidated balance sheets.

14. RECLAMATION AND MINE CLOSING COSTS

The majority of the Partnership’s operations are governed by various state statutes and the Federal Surface Mining Control and
Reclamation Act of 1977, which establish reclamation and mine closing standards. These regulations, among other requirements, require
restoration of property in accordance with specified standards and an approved reclamation plan. The Partnership has estimated the costs
and timing of future reclamation and mine closing costs and recorded those estimates on a present value basis using discount rates rang-
ing from 4.22% to 6.0%.

On January 1, 2003, the Partnership adopted SFAS No. 143, Accounting for Asset Retirement Obligations, which requires the fair value
of a liability for an asset retirement obligation to be recognized in the period in which it is incurred. Since the Partnership has historically
adhered to accounting principles similar to SFAS No. 143, this standard had no material effect on the Partnership’s consolidated financial
statements upon adoption.

Discounting resulted in reducing the accrual for reclamation and mine closing costs by $28,760,000 and $10,332,000 at December 31,
2004 and 2003, respectively. Estimated payments of reclamation and mine closing costs as of December 31, 2004 are as follows (in
thousands):

Year Ending December 31

2005
2006
2007
2008
2009
Thereafter

Aggregate undiscounted reclamation and mine closing
Effect of discounting

Total reclamation and mine closing costs
Less current portion

Reclamation and mine closing costs

1,180
2,327
3,779
558
264
54,670

62,778
28,760

34,018
(1,180)

32,838

The following table presents the activity affecting the reclamation and mine closing liability (in thousands):

Beginning balance
Accretion expense
Payments
Allocation of liability associated with

acquisition, mine development and
change in assumptions

Ending balance

Year Ended December 31,

2004

2003

2002

23,466
1,622
(899)

$ 23,456
1,341
(1,054)

20,518
1,365
(865)

9,829
34,018

(277)
$ 23,466

2,438
23,456

The reclamation and mine closing cost liability increase of $9,829,000 was primarily attributable to the Lodestar acquisition of
$4,129,000 described in Note 3 and the initial land disturbances associated with new operations at Mettiki Coal, LLC and Mettiki Coal
(WV), LLC of a combined $2,329,000. The liability also increased as the permitted refuse disposal areas were expanded at several existing
operations and a comprehensive study related to water treatment costs was completed. Collectively, these reclamation issues also
resulted in the effect of discounting increasing to $28,760,000 from $10,332,000.

15. PNEUMOCONIOSIS (“BLACK LUNG”) BENEFITS

Certain mine operating entities of the Partnership are liable under state statutes and the Federal Coal Mine Health and Safety Act of

1969, as amended, to pay black lung benefits to eligible employees and former employees and their dependents.

Pneumoconiosis (“black lung”) benefits liability is calculated using the service cost method. Under the service cost method the calcu-
lation of the actuarial present value of the estimated black lung obligation is based on an actuarial study performed by an independent
actuary. Actuarial gains or losses are amortized over the remaining service period of active miners. The discount rate used to calculate the
estimated present value of future obligations was 4.5% and 4.7% at December 31, 2004 and 2003, respectively.

The reconciliation of changes in benefit obligations at December 31, 2004 and 2003 is as follows (in thousands):

Benefit obligations at beginning of year
Service cost
Interest cost
Actuarial loss
Benefits and expenses paid
Benefit obligations at end of year

2004

2003

$17,633
1,217
1,091
549
(155)
$20,335

$16,067
947
978
65
(424)
$17,633

The U.S. Department of Labor has issued revised regulations that will alter the claims process for the federal black lung benefit
recipients. Both the coal and insurance industries have challenged certain provisions of the revised regulations through litigation, but the
regulations were upheld, with some exceptions as to the retroactive application of the regulations. The revised regulations are expected
to result in an increase in the incidence and recovery of black lung claims.

16. RELATED PARTY TRANSACTIONS

Administrative Services — The Partnership Agreement provides that the Managing GP and its affiliates be reimbursed for all direct
and indirect expenses it incurs or payments it makes on behalf of the Partnership, including, but not limited to, management’s salaries and
related benefits (including the LTIP), and accounting, budget, planning, treasury, public relations, land administration, environmental, per-
mitting, payroll, benefits, disability, workers’ compensation management, legal and information technology services. The Managing GP may
determine in its sole discretion the expenses that are allocable to the Partnership. Total costs billed by the Managing GP and its affiliates
to the Partnership were approximately $28,536,000, $12,471,000 and $6,559,000 for the years ended December 31, 2004, 2003 and 2002,
respectively. The increase from 2003 to 2004 and 2002 to 2003 were primarily attributable to higher accruals for the LTIP, STIP and
Supplemental Executive Retirement Plan ("SERP"). The expenses associated with LTIP and SERP were impacted by the market value of the
Partnership's Common Units, which had a closing market price of $74.00, $34.38 and $24.22 at December 31, 2004, 2003 and 2002, respec-
tively. The amounts billed by the managing GP include $24,242,000, $9,319,000 and $3,308,000 for the years ended December 31, 2004,
2003 and 2002, respectively, for the LTIP, STIP and SERP.

SGP Land — Webster County Coal, LLC (“Webster County Coal”) has a mineral lease and sublease with SGP Land requiring annual
minimum royalty payments of $2.7 million, payable in advance through 2013 or until $37.8 million of cumulative annual minimum and/or
earned royalty payments have been paid. Webster County Coal paid royalties of $4,611,000, $3,460,000 and $2,700,000 for the years ended
December 31, 2004, 2003 and 2002, respectively. Webster County Coal has recouped as earned royalties all advance minimum royalty pay-
ments made in accordance with these lease terms except for $805,000 as of December 31, 2004.

Warrior Coal has a mineral lease and sublease with SGP Land. Under the terms of the lease, Warrior Coal has paid and will
continue to pay in arrears an annual minimum royalty obligation of $2,270,000 until $15,890,000 of cumulative annual minimum and/or
earned royalty payments have been paid. The annual minimum royalty periods are from October 1 through the end of the following
September 30, expiring September 30, 2007. Warrior Coal paid royalties of $2,561,000, $2,453,000 and $2,127,000 for the years ended
December 31, 2004, 2003 and 2002, respectively. Warrior Coal has recouped as earned royalties all advance minimum royalty payments
made in accordance with these lease terms except for $636,000 as of December 31, 2004.

Under the terms of the mineral lease and sublease agreements described above, Webster County Coal and Warrior Coal also reim-
burse SGP Land for SGP Land’s base lease obligations. The Partnership reimbursed SGP Land $5,428,000, $4,395,000 and $3,922,000 for
the years ended December 31, 2004, 2003 and 2002, respectively, for the base lease obligations. Webster County Coal and Warrior Coal
have recouped as earned royalties all advance minimum royalty payments made in accordance with these terms except for $216,000 as of
December 31, 2004.

In 2001, SGP Land, as successor in interest to an unaffiliated third party, entered into an amended mineral lease with MC Mining, LLC
(“MC Mining”). Under the terms of the lease, MC Mining has paid and will continue to pay an annual minimum royalty obligation of
$300,000 until $6.0 million of cumulative annual minimum and/or earned royalty payments have been paid. MC Mining paid royalties of
$479,000 and $568,000 for the years ended December 31, 2003 and 2002, respectively. The 2004 annual minimum royalty obligation of
$300,000 was paid in January 2005. MC Mining has recouped as earned royalties all advance minimum royalty payments made under these
lease terms as of December 31, 2004.

The Partnership also has an option to lease and/or sublease certain reserves from SGP Land, which reserves are contiguous to the
Partnership’s Hopkins County Coal, LLC mining complex. Under the terms of the option to lease and sublease, the Partnership paid option
fees of $1,368,000 and $684,000 during the years ended December 31, 2004 and 2002, respectively. The 2003 option fee of $684,000 was
paid in January 2004 and is included in the due to affiliates balance as of December 31, 2003. The anticipated annual minimum royalty
obligation is $684,000, payable in advance through 2009.

Special GP — The Partnership has a noncancelable operating lease arrangement with the Special GP for the coal preparation plant
and ancillary facilities at the Gibson County Coal, LLC mining complex. Based on the terms of the lease, the Partnership will make monthly
payments of approximately $216,000 through January 2011. Lease expense incurred for each of the three years in the period ended
December 31, 2004 was $2,595,000.

The Partnership previously entered into and has maintained agreements with two banks to provide letters of credit in an aggregate
amount of $25.0 million (Note 8). At December 31, 2004, the Partnership had $22.2 million in outstanding letters of credit. The Special GP
guarantees these letters of credit. Historically, the Partnership has compensated the Special GP for a guarantee fee equal to 0.30% per
annum of the face amount of the letters of credit outstanding. During 2003 the Special GP agreed to waive the guarantee fee in exchange
for a parent guarantee from the Intermediate Partnership and Alliance Coal, LLC on the mineral lease and sublease with Webster County
Coal and Warrior Coal described above. Since the guarantee is made on behalf of entities within the consolidated partnership, the guar-
antee has no fair value under FIN No. 45 and does not impact the consolidated financial statements. The Partnership paid approximately
$31,300 and $48,200 in guarantee fees to the Special GP for the years ended December 31, 2003 and 2002, respectively.

17. COMMITMENTS AND CONTINGENCIES

Commitments — The Partnership leases buildings and equipment under operating lease agreements that provide for the payment
of both minimum and contingent rentals. The Partnership also has a noncancelable lease with the Special GP (Note 16). Future minimum
lease payments under operating leases are as follows (in thousands):

Year Ending December 31,

Affiliate

Others

Total

2005
2006
2007
2008
2009
Thereafter

2,595
2,595
2,595
2,595
2,595
2,810
15,785

2,071
1,650
819
264
13
–

4,817

4,666
4,245
3,414
2,859
2,608
2,810
20,602

Lease expense under all operating leases was $6,112,000, $5,490,000 and $4,707,000 for the years ended December 31, 2004, 2003

and 2002, respectively.

In October 2002, the Partnership entered into a master equipment lease. The Partnership’s credit facilities limit the amount of total
operating lease obligations to $10 million payable in any period of 12 consecutive months. This master equipment lease is subject to this
limitation on lease obligations. The Partnership entered into nine operating leases during 2003 under the master equipment lease with
lease terms ranging from three to six years. The Partnership did not enter into any new equipment leases under the master equipment lease
during 2004.

Contractual Commitments — In connection with planned capital projects, the Partnership had contractual commitments of approx-

imately $8.4 million at December 31, 2004.

General Litigation — The Partnership is involved in various lawsuits, claims and regulatory proceedings, incidental to its business.
The Partnership provides for costs related to litigation and regulatory proceedings, including civil fines issued as part of the outcome of
such proceedings, when a loss is probable and the amount is reasonably determinable. Although the ultimate outcome of these matters
cannot be predicted with certainty, in the opinion of management, the outcome of these matters, to the extent not previously provided for
or covered under insurance, are not expected to have a material adverse effect on the Partnership’s business, financial position or results
of operations. Nonetheless, these matters or estimates that are based on current facts and circumstances, if resolved in a manner differ-
ent from the basis on which management has formed its opinion, could have a material adverse effect on the Partnership’s financial posi-
tion or results of operations.

Other — During September 2004, the Partnership completed its annual property and casualty insurance renewal. As a result, the
Partnership and its affiliates retained a 10.0% participating interest along with its insurance carriers in the commercial property program.
The aggregate maximum limit in the commercial property program is $75 million per occurrence of which the Partnership would be respon-
sible for a maximum amount of $7.5 million for each occurrence, excluding a $3.5 million deductible.

Mettiki Coal (WV), LLC has proposed a long-wall underground mine extension (the “E-Mine”) to be located primarily in Tucker County,
West Virginia, which will eventually replace the Partnership’s Mettiki Coal, LLC’s existing long-wall mine, D-Mine located in Garrett County,
Maryland. The proposed mine, which will be either a long-wall or continuous mining operation, is approximately 10 miles from Mettiki Coal.
In order to proceed with the development of the E-Mine, Mettiki Coal (WV) filed two separate permit applications with the West Virginia
Department of Environmental Protection (“WVDEP”) concerning on-site disposal of scalp rock and underground mining, each requiring an
associated water discharge permit. The Partnership was notified on April 16, May 13, May 26, and June 7, 2004, that WVDEP has issued
the permits for on-site disposal of scalp rock, underground mining, water discharge related to the operation of the scalp rock disposal
facility, and water discharge related to the operation of the underground mine, respectively.

The appeal periods for the scalp rock permit and the two water discharge permits related to the operation of the scalp rock disposal
facility and underground mine have lapsed without any appeal being filed. Two appeals of the underground mining permit were filed on
June 11 and 16, 2004, respectively. The West Virginia Surface Mine Board (“SMB”) consolidated the appeals and held an administrative
initial hearing on October 19 and 20, 2004, December 7 and 8, 2004 and January 11 and February 7, 2005.

On March 8, 2005, the SMB issued a Final Order concluding consideration of the consolidated appeals without a decision, which Final
Order held that the SMB was unable to take any action relating to the issuance of the underground permit by WVDEP because its vote did
not obtain the concurrence of at least four SMB members as required by West Virginia law. Consequently, the ultimate decision by the
WVDEP to issue the underground permit was affirmed by operation of West Virginia law. In the Final Order, however, the SMB voted unan-
imously to require Mettiki Coal (WV) to increase the amount of a surety bond that serves as security for a portion of the reclamation plan
approved by WVDEP as part of the underground permit. On March 8, 2005, Mettiki Coal (WV) filed an appeal of the Final Order with the
Circuit Court of Tucker County, West Virginia, on the ground that the SMB was wrong in ordering Mettiki Coal (WV) to increase the surety
bond for part of the reclamation plan approved by WVDEP when the SMB, as a result of not obtaining the concurrence of at least four mem-
bers, failed to affirm the decision by WVDEP to issue a final order approving the underground permit issued by WVDEP on May 13, 2004.
On March 10, 2005 the West Virginia Rivers Coalition, the West Virginia Highlands Conservancy, and Trout Unlimited – West Virginia
Council filed an appeal of the SMB’s final order with the Circuit Court of Kanawha County, West Virginia. The appeal requests that the
Circuit Court (a) grant a stay of the WVDEP’s approval of the E-Mine permit pending a decision by the Circuit Court, (b) set a briefing sched-
ule and oral argument of the appeal and (c) reverse and vacate the WVDEP’s approval of the permit. Management believes the WVDEP’s
approval of the permit application will be ultimately upheld by the applicable Circuit Court in West Virginia.

On October 12, 2004, Pontiki Coal, LLC (“Pontiki”) was served with a complaint from ICG alleging a breach of contract and seeking
declaratory relief to determine the parties’ rights under a coal sales agreement between Horizon Natural Resource Sales Company
(“Horizon Sales”), as buyer, and Pontiki Coal Corporation, as seller, dated October 3, 1998, as amended on February 28, 2001 (the
“Agreement”). ICG has represented that it acquired the rights and assumed the liabilities of the Agreement effective September 30, 2004
as part of an asset sale approved by the U.S. bankruptcy court supervising the bankruptcy proceedings of Horizon Sales and its affiliates.
Pontiki is the successor-in-interest of Pontiki Coal Corporation as a result of a merger completed on August 4, 1999.

The complaint alleges that from January 2004 to August 2004, Pontiki failed to deliver a total of 138,111 tons of coal resulting in an
alleged loss of profits for ICG of $4.1 million. The Partnership has been unable to confirm ICG’s calculation of the alleged shortfall of coal
deliveries. The Partnership is aware that certain deliveries under the Agreement have not been made during 2004 for reasons including,
but not limited to, force majeure events at Pontiki and ICG’s failure to provide transportation services for the delivery of coal as required
under the Agreement. This litigation is in the preliminary stage and the Partnership does not believe that it is probable that a loss has been
incurred. The Partnership also does not believe that this litigation has merit and intends to contest the litigation vigorously. The Partnership
is unable, however, to predict the outcome of the litigation or reasonably estimate a range of possible loss given the current status of the
litigation.

At certain of the Partnership's operations, property tax assessments for several years are under audit by the related tax authorities.
The Partnership believes that it has recorded adequate liabilities based on reasonable estimates of any property tax assessments that may
be ultimately assessed as a result of these audits.

18.CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS

The Partnership has significant long-term coal supply agreements, some of which contain prospective price adjustment provisions
designed to reflect changes in market conditions, labor and other production costs and, when the coal is sold other than FOB the mine,
changes in transportation rates. Total revenues to major customers, including transportation revenues (Note 2), which exceed ten percent
of total revenues (Customer C comprised less than nine percent of total revenues in 2004) are as follows (in thousands):

Customer A
Customer B
Customer C

Year Ended December 31,

2004

2003

2002

124,847
89,887
56,658

116,750
78,724
52,561

113,094
72,224
69,933

Trade accounts receivable from these customers totaled approximately $24.3 million at December 31, 2004. The Partnership’s bad
debt experience has historically been insignificant, however the Partnership established an allowance of $763,000 during 2001, due to the
Partnership’s total credit exposure to Enron Corp., which filed for bankruptcy protection during December 2001. The Partnership received
$114,000 in 2004 for its claim against Enron and recognized as a recovery in 2004. Financial conditions of its customers could result in a
material change to this estimate in future periods. The coal supply agreements with Customers A, B and C expire in 2007, 2006 and 2010,
respectively.

19. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

A summary of the quarterly operating results for the Partnership is as follows (in thousands, except unit and per unit data):

Revenues
Operating income
Income before income taxes
Net income

Basic net income per limited partner unit
Diluted net income per limited

partner unit

Weighted average number of units

outstanding – basic

Weighted average number of units

outstanding – diluted

Quarter Ended

March 31,

2004 (1)

June 30,

2004

September 30,

December 31,

2004 (2)

2004 (3)

157,824
22,493
18,964
18,225

1.00

0.97

162,546
27,180
23,589
22,861

1.22

1.18

158,261
29,337
25,867
25,321

1.37

1.33

174,658
14,231
10,842
10,214

0.51

0.49

17,903,793

18,051,606

18,439,099

18,438,551

18,438,758

18,437,164

Revenues
Operating income
Income before income taxes
Net income

Basic net income per limited partner unit
Diluted net income per limited

partner unit

Weighted average number of units

outstanding - basic

Weighted average number of units

outstanding - diluted

Quarter Ended

March 31,

2003

June 30,

2003

September 30,

December 31,

2003

124,925
18,057
14,083
13,128

0.81

0.79

133,471
12,781
9,248
8,528

0.47

0.45

141,799
15,210
11,466
10,803

0.59

0.57

142,552
19,038
15,682
15,443

0.85

0.82

16,593,609

17,903,793

17,176,824

18,485,741

18,487,787

18,486,098

Operating income in the above table represents income from operations before interest expense.

(1) The Partnership’s March 31, 2004 quarterly results were impacted by extra expenses associated with extinguishing the Dotiki Fire
Incident, in addition the Partnership recognized as an offset to operating expenses $2.9 million representing estimated insurance
recoveries for expenses incurred as a result of the Dotiki Fire Incident (Note 4).

(2) The Partnership’s September 30, 2004 quarterly results were impacted by an offset to operating expenses of $2.8 million due to the
final settlement of insurance claims attributable to the Dotiki Fire Settlement and a net gain from insurance settlement of approxi-
mately $15.2 million attributable to the final settlement of insurance claims attributable to the Dotiki Fire Incident (Note 4).

(3) The Partnership’s December 31, 2004 quarterly results were impacted by an accrual of $4.1 million reflecting the Partnership’s initial
estimate of certain minimum costs attributable to the MC Mining Fire Incident that are not reimbursable under the Partnership’s insur-
ance policies (Note 4).

(4) The Partnership’s December 31, 2003 quarterly results were impacted by a contractual modification that resulted in a $2.0 million
favorable pricing adjustment associated with coal feedstock sales to Synfuel Solutions Operating LLC for shipments made primarily in
2003 but prior to the fourth quarter of 2003. Additionally, operating expenses decreased due to the reversal of an expense accrual of
$1.2 million established in 1998. The expense accrual was established in conjunction with the idling of Pontiki in 1998 that created
an expectation of a probable increase in workers’ compensation costs associated with the terminated workforce. The expected
anticipated increase in workers’ compensation claims did not emerge and, with limited exceptions, the statute of limitations expired
in December 2003 for the filing or reopening of workers’ compensation claims associated with the employee terminations.

20. SUBSEQUENT EVENT

On January 1, 2005 the Partnership acquired 100% of the limited liability company member interest of Tunnel Ridge, LLC from Alliance

Resource Holdings, Inc., a company owned by management of the Partnership (Note 3).

******

SCHEDULE II

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2004, 2003, AND 2002

2004
Allowance for doubtful accounts

2003
Allowance for doubtful accounts

2002
Allowance for doubtful accounts

Balance At
Beginning
Of year

Additions
Charged To
Income

Deductions

Balance At
End Of Year

(in thousands)

$ 763

$ –

$ 763

$ –

$ 763

$ –

$ 763

$ –

$ 763

The Partnership established an allowance of $763,000 during 2001 due to the Partnership's total credit exposure to Enron Corp. which
filed for bankruptcy protection during December 2001. In 2004, the Partnership collected approximately $114,000 from the sale to a third-
party of a bankruptcy claim relating to this receivable to a third-party. The remaining balance of $649,000 was written-off.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures. The Partnership maintains controls and procedures designed to ensure that it is able to
collect the information it is required to disclose in the reports it files with the SEC, and to process, summarize and disclose this informa-
tion within the time periods specified in the rules of the SEC. An evaluation of the effectiveness of the design and operation of our disclo-
sure controls and procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Securities Exchange Act) was performed as of the end
of the period covered by the date of this report. This evaluation was performed under the supervision and with the participation of our man-
agement, including our Chief Executive Officer and Chief Financial Officer. Based on an evaluation of the Partnership's disclosure controls
and procedures as of the end of the period covered by this report conducted by the Partnership's management, with the participation of
our Chief Executive and Chief Financial Officers, our Chief Executive and Chief Financial Officers believe that these controls and procedures
are effective to ensure that the Partnership is able to collect, process and disclose the information it is required to disclose in the reports
it files with the SEC within the required time periods, and there were no material changes in internal control over financial reporting occur-
ring in the fourth quarter of 2004.

Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls or our
internal controls over financial reporting ("internal controls") will prevent all errors and all fraud. A control system, no matter how well con-
ceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the
design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered rela-
tive to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that
all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities
that judgments in decision-making can be faulty, and that simple errors or mistakes can occur. Additionally, controls can be circumvented
by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any
system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that
any design will succeed in achieving its stated goals under all potential future conditions. Over time, controls may become inadequate
because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent
limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our disclo-
sure controls and internal controls and make modifications as necessary; our intent in this regard is that the disclosure controls and the
internal controls will be maintained as systems change and conditions warrant.

Management's Annual Report on Internal Control over Financial Reporting. Management of the Partnership is responsible for
establishing and maintaining effective internal control over financial reporting as defined in Rules 13a-15(f) under the Securities Exchange
Act of 1934. The Partnership's internal control over financial reporting is designed to provide reasonable assurance to the Partnership's
management and board of directors regarding the preparation and fair presentation of published financial statements. Our controls are
designed to provide reasonable assurance that the Partnership's assets are protected from unauthorized use and that transactions are exe-
cuted in accordance with established authorizations and properly recorded. The internal controls are supported by written policies and are
complemented by a staff of component business process owners and an internal auditor supported by competent and qualified external
resources used to assist in testing the operating effectiveness of the Partnership's internal control over financial reporting. Management
believes that the design and operations of our internal controls over financial reporting at December 31, 2004 are effective and provide
reasonable assurance that the books and records accurately reflect the transactions of the Partnership.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even
those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and
presentation.

Management assessed the effectiveness of the Partnership's internal control over financial reporting as of December 31, 2004. In
making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO) in Internal Control – Integrated Framework. Based on our assessment, we believe that, as of December 31, 2004, the
Partnership's internal control over financial reporting is effective based on those criteria, and we believe that we have no material
internal control weaknesses in our financial reporting process.

Management's assessment of the effectiveness of internal control over financial reporting as of December 31, 2004, has been
audited by Deloitte & Touche, LLP, the independent registered public accounting firm, which also audited the Partnership's consolidated
financial statements. Deloitte & Touche's attestation report on management's assessment of the Partnership's internal control over finan-
cial reporting appears below.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of the Managing
General Partner and the Partners of
Alliance Resource Partners, L.P.:

We have audited management’s assessment, included in the accompanying Management’s Annual Report on Internal Control Over
Financial Reporting, that Alliance Resource Partners, L.P. and subsidiaries (the “Partnership”) maintained effective internal control over
financial reporting as of December 31, 2004, based on criteria established in Internal Control – Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission. The Partnership’s management is responsible for maintaining effec-
tive internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our
responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Partnership’s internal con-
trol over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over finan-
cial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial
reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and per-
forming such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis
for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal
executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, man-
agement, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of finan-
cial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over finan-
cial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately
and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that
receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the com-
pany; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the
company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper man-
agement override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, pro-
jections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that
the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures
may deteriorate.

In our opinion, management’s assessment that the Partnership maintained effective internal control over financial reporting as of
December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control – Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Partnership maintained, in all
material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal
Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the con-
solidated balance sheets as of December 31, 2004 and 2003 and the related consolidated statements of income, cash flows and Partners’
capital (deficit) and comprehensive income for each of the three years in the period ended December 31, 2004 and the financial statement
schedule listed in the Index at Item 15 of the Partnership, and our report dated March 15, 2005 expressed an unqualified opinion on those
financial statements and financial statement schedule.

/s/ Deloitte & Touche LLP

Tulsa, Oklahoma
March 15, 2005

ITEM 9B. OTHER

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS OF THE

MANAGING GENERAL PARTNER

As is commonly the case with publicly-traded limited partnerships, we are managed and operated by our managing general partner.
The following table shows information for the directors and executive officers of our managing general partner. Executive officers and
directors are elected until death, resignation, retirement, disqualification, or removal.

Name

Age

Position With our Managing General Partner

Joseph W. Craft III

Robert G. Sachse

Thomas L. Pearson

Charles R. Wesley

Brian L. Cantrell

Gary J. Rathburn

Michael J. Hall

John J. MacWilliams

Preston R. Miller, Jr.

John P. Neafsey

John H. Robinson

President, Chief Executive Officer and Director

Executive Vice President and Vice Chairman of the Board

Senior Vice President – Law and Administration,
General Counsel and Secretary

Senior Vice President – Operations

Senior Vice President – Chief Financial Officer

Senior Vice President – Marketing

Director and Member of the Audit* and Conflicts Committees

Director

Director and Member of the Compensation* Committee

Chairman of the Board and Member of Audit, Compensation
and Conflicts Committees

Director and Member of Audit, Compensation and Conflicts*
Committees

*Indicates Chairman of Committee

Joseph W. Craft III has been President, Chief Executive Officer and a Director since August 1996 and has indirect majority owner-
ship of our managing general partner. Previously Mr. Craft served as President of MAPCO Coal Inc. since 1986. During that period, he also
was Senior Vice President of MAPCO Inc. and had been previously that company's General Counsel and Chief Financial Officer. Before join-
ing MAPCO, Mr. Craft was an attorney at Falcon Coal Corporation and Diamond Shamrock Coal Corporation. He is past Chairman of the
National Coal Council, a Board and Executive Committee Member of the National Mining Association, and a Director of the Center for
Energy and Economic Development. Mr. Craft holds a Bachelor of Science degree in Accounting and a Juris Doctor degree from the
University of Kentucky. Mr. Craft also is a graduate of the Senior Executive Program of the Alfred P. Sloan School of Management at
Massachusetts Institute of Technology.

Robert G. Sachse has been Executive Vice President and Vice Chairman since August 2000. Prior to his current position, Mr. Sachse
was Executive Vice President and Chief Operating Officer of MAPCO Inc. from 1996 to 1998 when MAPCO merged with The Williams
Companies. Following the merger, Mr. Sachse had a two year non-compete consulting agreement with The Williams Companies. Mr.
Sachse held various positions while with MAPCO Coal Inc. from 1982 to 1991, and was promoted to President of MAPCO Natural Gas
Liquids in 1992. Mr. Sachse holds a Bachelor of Science degree in Business Administration from Trinity University and a Juris Doctor degree
from the University of Tulsa.

Thomas L. Pearson has been Senior Vice President – Law and Administration, General Counsel and Secretary since August 1996.
Mr. Pearson previously was Assistant General Counsel of MAPCO Inc., and served as General Counsel and Secretary of MAPCO Coal Inc.
from 1989 to 1996. Before joining the company, he was General Counsel and Secretary of McLouth Steel Products Corporation, Corporate
Counsel for Midland-Ross Corporation, and an attorney for Arter & Hadden, a law firm in Cleveland, Ohio. Mr. Pearson's current and past
business, charitable and education involvement includes Trustee of the Energy and Mineral Law Foundation, Vice Chairman, Legal Affairs
Committee, National Mining Association, and Member, Dean's Committee, The University of Iowa College of Law. Mr. Pearson holds a
Bachelor of Arts degree in History and Communications from DePauw University and a Juris Doctor degree from The University of Iowa.

Charles R. Wesley has been Senior Vice President – Operations since August 1996. He joined the company in 1974 when he began
working for Webster County Coal Corporation as an engineering co-op student. In 1992, Mr. Wesley was named Vice President – Operations
for Mettiki Coal Corporation. He has served the industry as past President of the West Kentucky Mining Institute and National Mine Rescue
Association Post 11, and he has served on the Board of the Kentucky Mining Institute. Mr. Wesley holds a Bachelor of Science degree in
Mining Engineering from the University of Kentucky.

Brian L. Cantrell was named Senior Vice President and Chief Financial Officer in October 2003. Prior to his current position, Mr.
Cantrell was President of AFN Communications, LLC from November 2001 to October 2003 where he had previously served as Executive
Vice President and Chief Financial Officer after joining AFN in September 2000. Mr. Cantrell's previous positions include Chief Financial
Officer, Treasurer and Director with Brighton Energy, LLC from August 1997 to September 2000; Vice President – Finance of KCS Medallion
Resources, Inc.; and Vice President – Finance, Secretary and Treasurer of Intercoast Oil and Gas Company. Mr. Cantrell is a Certified Public
Accountant and holds a Master of Accountancy and Bachelor of Accountancy from the University of Oklahoma.

Gary J. Rathburn has been Senior Vice President – Marketing since August 1996. He joined MAPCO Coal Inc. as Manager of
Brokerage Coals in 1980. Since that time, he has managed all phases of the marketing group involving transportation and distribution, inter-
national sales and the brokering of coal. Prior to joining the company, Mr. Rathburn was employed by Eastern Associated Coal Corporation
in its International Sales and Brokerage groups. Active in many industry-related groups, he was a Director of The National Coal Association
and Chairman of the Coal Exporters Association for several years. Mr. Rathburn holds a Bachelor of Arts degree in Political Science from
the University of Pittsburgh and has participated in industry-related programs at the World Trade Institute, Princeton University and the
Colorado School of Mines.

Michael J. Hall became a Director in March 2003. Mr. Hall was Vice President – Finance and Chief Financial Officer, Secretary and
Treasurer of Matrix Service Company (Matrix) from September, 1998 until he retired in May, 2004. He continues to serve on Matrix's Board
of Directors, a position he assumed when he joined Matrix in 1998. Matrix is a company which provides general industrial construction and
repair and maintenance services principally to the petroleum, petrochemical, power, bulk storage terminal, pipeline and industrial gas
industries. Mr. Hall was responsible for all financial and administrative functions including accounting, financial reporting, auditing,
finance, budgeting, tax, risk management, investor relations, human resources and information technology. Prior to working for Matrix, Mr.
Hall was Vice President and Chief Financial Officer of Pexco Holdings, Inc., Vice President – Finance and Chief Financial Officer for
Worldwide Sports & Recreation, Inc. an affiliated company of Pexco and worked for T.D. Williamson, Inc., as Senior Vice President, Chief
Financial and Administrative Officer, and Director of Operations – Europe, Africa and Middle East Region. Mr. Hall holds a Bachelor of
Science degree in Accounting from Boston College and a Master of Business Administration from Stanford University. Mr. Hall is chairman
of the audit committee and a member of the conflicts committee.

John J. MacWilliams, is a Partner of The Tremont Group, LLC, a private equity investment firm founded in January 2003, located in
Newton, MA., which has specialized expertise in the energy industry. Mr. MacWilliams is also a General Partner of The Beacon Group, LP,
which he joined in 1993, and has served as a Director since June 1996. As part of the Beacon Group, he co-manages two private equity
funds focusing on the energy industry. Mr. MacWilliams' previous positions include serving as a General Partner of JP Morgan Partners,
Executive Director of Goldman Sachs International in London, Vice President for Goldman Sachs & Co.'s Investment Banking Division in
New York, and as an attorney at Davis Polk & Wardwell in New York. He also is a Director of Compagnie Generale de Geophysique. Mr.
MacWilliams holds a Bachelor of Arts degree from Stanford University, Master of Science degree from Massachusetts Institute of
Technology, and a Juris Doctor degree from Harvard Law School.

Preston R. Miller, Jr., is a Partner of The Tremont Group, LLC, a private equity investment firm founded in January 2003, located in
Newton, MA., which has a specialized expertise in the energy industry. Mr. Miller is a General Partner of The Beacon Group, LP that he
joined in 1993 and has served as a Director since June 1996. As a part of The Beacon Group, he co-manages two private equity funds focus-
ing on the energy industry. Mr. Miller's previous positions include serving as a General Partner of JP Morgan Partners from June 2000
through December 2002, and was with Goldman Sachs & Co.’s from January 1979 through January 1993, most recently as Vice President
in the Structured Finance Group in New York City where he had global responsibility for coverage of the independent power industry, asset-
backed power generation, and oil and gas financing. He also has a background in credit analysis, and was head of the revenue bond rat-
ing group at Standard & Poor's Corp. Mr. Miller holds a Bachelor of Arts degree from Yale University and a Master of Public Administration
degree from Harvard University. Mr. Miller is the chairman of the compensation committee.

John P. Neafsey has served as Chairman since June 1996. Mr. Neafsey is President of JN Associates, an investment consulting firm
formed in 1993. Mr. Neafsey served as President and CEO of Greenwich Capital Markets from 1990 to 1993 and a Director since its found-
ing in 1983. Positions that Mr. Neafsey held during a 23-year career at The Sun Company include Director, Executive Vice President respon-
sible for Canadian operations, Sun Coal Company and Helios Capital Corporation; Chief Financial Officer; and other executive positions with
numerous subsidiary companies. He is or has been active in a number of organizations, including the following: Director for The West
Pharmaceutical Services Company and Chairman of both Constar, Inc. and NES Rentals, Inc., Trustee Emeritus and Presidential Counselor,
Cornell University, and Overseer of Cornell-Weill Medical Center. Mr. Neafsey holds Bachelor and Master of Science degrees in Engineering
and a Master of Business Administration degree from Cornell University. Mr. Neafsey is a Member of the audit, conflicts and compensa-
tion committees.

John H. Robinson became a Director in December 1999. Mr. Robinson is Vice Chairman of Olsson Associates, an engineering
consultancy. From 2003 to 2004, he was Chairman of EPC Global, Ltd., an engineering staffing company, and President of Metilinix, Inc., a
system optimization software company. From 2000 to 2002, he was Executive Director of Amey plc, a British business process outsourcing
company. Mr. Robinson served as Vice Chairman of Black & Veatch from 1998 to 2000. He began his career at Black & Veatch in 1973 and
was a General Partner and Managing Partner prior to becoming Vice Chairman when the firm incorporated. Mr. Robinson is a Director of
Coeur d'Alene Mining Corporation. Mr. Robinson holds Bachelor and Master of Science degrees in Engineering from the University of
Kansas and is a graduate of the Owner-President-Management Program at the Harvard Business School. He is chairman of the conflicts
committee and a member of the audit and compensation committees.

Audit Committee

The audit committee is comprised of three non-employee members of the board of directors (currently, Mr. Hall, Mr. Neafsey and Mr.
Robinson). After reviewing the qualifications of the current members of the audit committee, and any relationships they may have with us
that might affect their independence, the board of directors has determined that all current audit committee members are “independent”
as that concept is defined in Section 10A of the Exchange Act, all current audit committee members are “independent” as that concept is
defined in the applicable rules of the NASDAQ, all current audit committee members are financially literate, and Mr. Hall and Mr. Neafsey
qualify as audit committee financial experts under the applicable rules promulgated pursuant to the Exchange Act.

Report of the Audit Committee. The audit committee of Alliance Resource Management GP, LLC, oversees our Partnership's financial
reporting process on behalf of the board of directors. Management has the primary responsibility for the financial statements and the
reporting process including the systems of internal controls. The audit committee has the responsibility for the appointment, compensation
and oversight of the work of our independent registered public accounting firm and will assist the board of directors by conducting its own
review of our:

– filings with the Securities and Exchange Commission (the “SEC”) and the Securities Act of 1933 and the Securities Exchange Act

of 1934 (the “Exchange Act”) (i.e., Forms 10-K, 10-Q, and 8-K);

– press releases and other communications by the Partnership to the public concerning earnings, financial condition and results of

operations, including changes in distribution policies or practices affecting the holders of Partnership units;

– systems of internal controls regarding finance and accounting that management and the board of directors have established; and

– auditing, accounting and financial reporting processes generally.

In fulfilling its oversight and other responsibilities, the audit committee either met or took action in the form of written consents
eleven times during 2004. The audit committee’s activities included, but were not limited to, (a) the selection of the independent registered
public accounting firm, (b) meeting periodically in executive session with the independent registered public accounting firm, (c) the review
of the Quarterly Reports on Form 10-Q for the three months ended March 31, June 30, and September 30, 2004, (d) performing a self-
assessment of the committee itself and (e) reviewing and amending the audit committee charter. Based on the results of the self-assess-
ment, the audit committee believes that it satisfied the requirements of its charter. The audit committee also reviewed and discussed with
management and the independent registered public accounting firm this Annual Report on Form 10-K, including the audited financial
statements.

The Partnership's independent registered public accounting firm, Deloitte & Touche, LLP, are responsible for expressing an opinion on
the conformity of the audited financial statements with generally accepted accounting principles. The audit committee reviewed with
Deloitte & Touche, LLP their judgment as to the quality, not just the acceptability, of the Partnership's accounting principles and such other
matters as are required to be discussed with the audit committee under generally accepted auditing standards.

The audit committee discussed with Deloitte & Touche, LLP the matters required to be discussed by SAS 61 (Codification of Statement
on Auditing Standards, AU § 380), as may be modified or supplemented. The committee received written disclosures and the letter from
Deloitte & Touche, LLP required by Independence Standards Board No. 1., Independence Discussions with Audit Committees, as may be
modified or supplemented, and has discussed with Deloitte & Touche, LLP its independence from management and the Partnership.

Based on the reviews and discussions referred to above, the audit committee recommended to the board of directors that the
audited financial statements be included in the Annual Report on Form 10-K for the year ended December 31, 2004 for filing with the SEC.

Members of the Audit Committee:

Michael J. Hall, Chairman

John P. Neafsey

John H. Robinson

Code of Ethics

We have adopted a Code of Ethics with which our chief executive officer and our senior financial officers (including our principal finan-
cial officer, and our principal accounting officer or controller), are expected to comply. The Code of Ethics is publicly available on our web-
site under Investors Relations at www.arlp.com and is available in print to any unitholder who requests it. If any substantive amendments
are made to the Code of Ethics or if there is a grant of a waiver, including any implicit waiver, from a provision of the code to our chief
executive officer, chief financial officer, chief accounting officer or controller, we will disclose the nature of such amendment or waiver on
our website or in a report on Form 8-K.

Communications with the Board

Unitholders or other interested parties can contact any director or committee of the board by writing to them c/o Senior Vice President
– Law and Administration, General Counsel and Secretary, P. O. Box 22027, Tulsa, Oklahoma 74121-2027. Comments or complaints relat-
ing to our accounting, internal accounting controls or auditing matters will also be referred to members of the audit committee. The audit
committee has procedures for (a) receipt, retention and treatment of complaints received by us regarding accounting, internal accounting
controls, or auditing matters and (b) the confidential, anonymous submission by our employees of concerns regarding questionable account-
ing or auditing matters.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities and Exchange Act of 1934, as amended, requires directors, executive officers and persons who
beneficially own more than ten percent of a registered class of our equity securities to file with the SEC initial reports of ownership and
reports or changes in ownership of such equity securities. Such persons are also required to furnish us with copies of all Section 16(a)
forms they file. Based solely upon a review of the copies of the forms furnished to us, or written representations from certain reporting
persons, we believe that during 2004 none of our officers and directors were delinquent with respect to any of the filing requirements under
Rule 16(a) other than Mr. Sachse who did not timely file a Form 4 related to his purchase of 104 units on October 4, 2004, but has since
filed a Form 4 with respect to this transaction.

Reimbursement of Expenses of our Managing General Partner and its Affiliates

Our managing general partner does not receive any management fee or other compensation in connection with its management of
us. However, our managing general partner and its affiliates, including Alliance Resource Holdings, perform services for us and are reim-
bursed by us for all expenses incurred on our behalf, including the costs of employee, officer and director compensation and benefits prop-
erly allocable to us, as well as all other expenses necessary or appropriate to the conduct of our business, and properly allocable to us.
Our partnership agreement provides that our managing general partner will determine the expenses that are allocable to us in any reason-
able manner determined by our managing general partner in its sole discretion.

ITEM 11. EXECUTIVE COMPENSATION

Executive Compensation

The following table sets forth certain compensation information for the chief executive officer and each of the four other most highly
compensated executive officers of our managing general partner in excess of $100,000 in 2004, 2003 and 2002. We reimburse our manag-
ing general partner and its affiliates for expenses incurred on our behalf, including the cost of officer compensation allocable to us.

Summary Compensation Table

Annual Compensation

Name and Principal Position

Year

Salary

Bonus (1)

Other Annual
Compensation (2)

Long-Term
Compensation
Payouts (3)

All Other
Compensation
(4)

Joseph W. Craft III,
President, Chief Executive Officer
and Director

Thomas L. Pearson,
Senior Vice President-Law and
Administration, General Counsel and Secretary

Charles R. Wesley,
Senior Vice President-Operations

Gary J. Rathburn,
Senior Vice President-Marketing

Thomas M. Wynne
Vice President-Operations

2004
2003
2002

$341,267
334,828
328,955

203,520
199,680
196,178

229,612
215,665
211,504

177,020
173,680
170,634

164,631
153,600
144,462

375,000
387,000
227,000

225,000
166,000
83,000

300,000
234,500
130,000

222,000
171,000
90,000

222,000
150,000
60,000

$3,521
3,400
1,075

–
–
1,750

825
–
–

–
–
2,285

–
–
–

$ 8,286,600
–
–

$79,479
62,694
52,171

1,473,746
–
–

1,657,320
–
–

1,508,939
–
–

1,154,205
–
–

39,435
31,481
32,631

75,320
37,115
33,001

38,790
30,602
29,884

45,377
17,448
16,102

(1) Amounts awarded under the Short-Term Incentive Plan. Please see “Short-Term Incentive Plan” below.
(2) Amounts reimbursed for income tax preparation and financial planning services.
(3) Amounts represent the market value of the LTIP grants for the years 2002, 2001 and 2000 that vested in November 2004.
(4) Amounts represent (a) our managing general partner’s matching contributions to its profit sharing and savings plan, (b) our managing
general partner’s contribution to its Supplemental Executive Retirement Plan (SERP), and (c) the amounts for Mr. Wesley and Mr.
Wynne include a non Short-Term Incentive Plan bonus approved by the compensation committee.

Compensation of Directors

Under our managing general partner’s Directors' Compensation Program (Directors’ Plan) each non-employee director was paid an
annual retainer of $22,500 during 2004. The annual retainer is payable in common units to be paid on a quarterly basis in advance
determined by dividing the pro rata annual retainer payable on such date by the closing sales price per common unit averaged over the
immediately preceding ten trading days. Each non-employee director is eligible to participate in a deferred compensation plan that is
administered by the compensation committee. Prior to the beginning of each plan year, each non-employee director may elect to defer all
or a portion of his compensation until he ceases to be a member of the board of directors. A new election must be made for each plan year.
For compensation deferred by a director, a notional account is established and credited with “phantom” units equal to the number of com-
mon units deferred. In addition, when distributions are made with respect to common units, the notional account is credited with “phan-
tom” distributions with respect to phantom units that are equal in amount to the distributions made with respect to common units. The
board of directors may change or terminate the deferred compensation plan at any time; provided, however, that accrued benefits under
the deferred benefit plan cannot be impaired.

In addition, each non-employee director is entitled to participate in the Long-Term Incentive Plan. Under the Long-Term Incentive Plan
such directors receive annual grants of restricted units, which vest in accordance with the procedures described below. Please see “Long-
Term Incentive Plan” below.

Mr. Sachse has a consulting agreement with our managing general partner with an indefinite term, subject to termination by either
party upon receipt of ninety-day advance written notice of termination. The consulting agreement provides that Mr. Sachse will serve as
Executive Vice President of our managing general partner and devote his services on a part-time basis. In addition to compensation received
under the Directors' Plan described above and Long-Term Incentive Plan described below, Mr. Sachse is entitled to receive an annual fee
of $150,000, payable in arrears monthly. Mr. Sachse also is entitled to receive quarterly payments of $7,500, payable in common units of
the Partnership. Copies of Mr. Sachse's original consulting agreement and the letter agreement extending the term of the original agree-
ment are exhibits hereto.

Employment Agreements

The executive officers of our managing general partner and some additional members of senior management will enter into employ-
ment agreements among the executive officer or member of senior management, on the one hand, and our managing general partner on
the other. We reimburse our managing general partner for the compensation and benefits costs under these agreements. This summary of
the terms of the employment agreements does not purport to be complete, but outlines their material provisions. A form of the agreements
with each of Mr. Craft, Mr. Pearson, Mr. Wesley and Mr. Rathburn is an exhibit hereto.

Each of the form of employment agreements had an initial term that expired on December 31, 2002, but automatically extend for suc-
cessive one-year terms unless either party gives 12 months prior notice to the other party. The form of employment agreements provide for
a base salary, subject to review annually, of $334,828, $199,680, $225,280 and $173,680 for Mr. Craft, Mr. Pearson, Mr. Wesley and Mr.
Rathburn, respectively. Differences between these base salaries as compared to the base salaries reported in the summary compensation
table are attributable to the number of weekly pay periods in a calendar year. The employment agreements provide for continued salary
payments, bonus and benefits for a period of three years, in the case of Mr. Craft, and 18 months, in the case of Messrs. Pearson, Wesley
and Rathburn, following termination of employment, except in the case of a change of control of our managing general partner.

In the case of a “change of control” as defined in the agreements, in lieu of the continuation of salary and benefits, that executive
will be entitled to a lump sum payment in an amount equal to three times base salary plus bonus, in the case of Mr. Craft, and two times
base salary plus bonus in the case of Messrs. Pearson, Wesley and Rathburn. Unless the executive waives his or her right to the continu-
ation of base salary and bonus, the agreements provide for a noncompetition period of 18 months. The noncompetition period does not
apply after a change in control. Amounts paid by our managing general partner pursuant to the employment agreements will be reimbursed
by us.

The executives who are subject to employment agreements also participate in the Short- and Long-Term Incentive Plans of our
managing general partner described below along with other members of management. They also are entitled to participate in the other
employee benefit plans and programs that our managing general partner provides for its employees.

Long-Term Incentive Plan

Effective January 1, 2000, our managing general partner adopted the Long-Term Incentive Plan (LTIP) for certain employees and direc-
tors of our managing general partner and its affiliates who perform services for us. The summary of the LTIP contained herein does not pur-
port to be complete, but outlines its material provisions.

The LTIP is administered by the compensation committee of our managing general partner's board of directors. Annual grant levels
for designated participants are recommended by the president and chief executive officer of our managing general partner, subject to the
review and approval of the compensation committee. We will reimburse our managing general partner for all costs incurred pursuant to
the programs described below. Grants are made of either restricted units, which are "phantom" units that entitle the grantee to receive a
common unit or an equivalent amount of cash upon the vesting of a phantom unit, or options to purchase common units. Common units to
be delivered upon the vesting of restricted units or to be issued upon exercise of a unit option will be acquired by our managing general
partner in the open market at a price equal to the then prevailing price, or directly from Alliance Resource Holdings or any other third party,
including units newly issued by us, or use units already owned by our managing general partner, or any combination of the foregoing. Our
managing general partner is entitled to reimbursement by us for the cost incurred in acquiring these common units or in paying cash in lieu
of common units upon vesting of the restricted units. If we issue new common units upon payment of the restricted units or unit options
instead of purchasing them, the total number of common units outstanding will increase.

The aggregate number of units reserved for issuance under the LTIP is 600,000. Effective January 1, 2004, the compensation commit-
tee approved an amendment to the LTIP clarifying that if an award is paid or settled in cash rather than through the delivery of units, then
the units granted by such award shall be available with respect to which options and restricted units may be granted under the LTIP in the
future. A copy of the amendment is an exhibit hereto. During 2004 and 2003 the compensation committee approved grants of 102,785 and
141,205 restricted units, which will vest December 31, 2006 and September 30, 2005 subject to the satisfaction of certain financial tests.
As of December 31, 2004, 2,765 outstanding LTIP grants have been forfeited. Effective as of January 1, 2005, the compensation commit-
tee approved additional grants of 57,195 restricted units, which vest on January 1, 2008 subject to the satisfaction of certain financial tests.
As of March 1, 2005 there were 70,454 common units available for future issuance under the LTIP assuming all grants currently issued and
outstanding for calendar years 2003, 2004 and 2005 are settled with common units.

In November 2004, the initial LTIP vesting requirements were met when we satisfied the final conversion financial tests for convert-
ing the remaining subordinated units into common units. As a result, LTIP grants for the years 2000, 2001 and 2002 of 385,210 units vest-
ed in November 2004. We issued 231,126 common units to participants and paid cash to or on behalf of participants for the equivalent of
154,084 units to satisfy personal income tax obligations.

Restricted Units. Restricted units will vest over a period of time as determined by the compensation committee. However, if a
grantee's employment is terminated for any reason prior to the vesting of any restricted units, those restricted units will be automatically
forfeited, unless the compensation committee, in its sole discretion, provides otherwise.

The issuance of the common units pursuant to the vesting of restricted units under the LTIP is intended to serve as a means of incen-
tive compensation for performance and not primarily as an opportunity to participate in the equity appreciation in respect of the common
units. Therefore, no consideration will be payable by the plan participants upon receipt of the common units, and we receive no remuner-
ation for these units. The compensation committee, in it discretion, may grant distribution equivalent rights with respect to restricted units.

Unit Options. We have not made any grants of unit options. The compensation committee, in the future, may decide to make unit
option grants to employees and directors containing the specific terms as the committee determines. When granted, unit options will have
an exercise price set by the compensation committee which may be above, below or equal to the fair market value of a common unit on
the date of grant.

Our managing general partner's board of directors, in its discretion, may terminate the LTIP at any time with respect to any common
units for which a grant has not previously been made. Our managing general partner's board of directors will also have the right to alter
or amend the LTIP or any part of it from time to time, subject to unitholder approval as required by the exchange upon which the common
units may be listed at that time; provided, however, that no change in any outstanding grant may be made that would materially impair the
rights of the participant without the consent of the affected participant. In addition, our managing general partner may, in its discretion,
establish such additional compensation and incentive arrangements as it deems appropriate to motivate and reward its employees. Our
managing general partner is reimbursed for all compensation expenses incurred on our behalf.

Long-Term Incentive Plan – Awards in Last Fiscal Year

Number of
Units (1)

28,000
6,300
10,400
6,400
4,350

Performance or
Other Period Until
Maturation or
Payout (2)

36 Months
36 Months
36 Months
36 Months
36 Months

Joseph W. Craft III
Thomas L. Pearson
Charles R. Wesley
Gary J. Rathburn
Thomas M. Wynne

(1) Units granted under the LTIP will vest December 31, 2006, subject to certain financial tests.
(2) The number of units granted is not subject to minimum thresholds, targets or maximum payout conditions. However, the vesting of

these grants is subject to meeting certain financial tests.

Short-Term Incentive Plan

Our managing general partner maintains a STIP for management and other salaried employees. The STIP is designed to enhance the
financial performance by rewarding management and selected salaried employees and those of our managing general partner with cash
awards for our achieving an annual financial performance objective. The annual performance objective for each year is recommended by
the president and chief executive officer of our managing general partner and approved by the compensation committee of its board of
directors prior to or during January of that year. The STIP is administered by the compensation committee. Individual participants and pay-
ments each year are determined by and in the discretion of the compensation committee, and our managing general partner is able to
amend the plan at any time. Our managing general partner is entitled to reimbursement by us for the costs incurred under the STIP.

Supplemental Executive Retirement Plan

Our managing general partner maintains a Supplemental Executive Retirement Plan (SERP) for certain officers and key employees.
The purpose of the SERP is to enhance our ability to retain specific officers and key employees, by providing them with the deferred com-
pensation benefits contained in the SERP. The intent of the SERP is to provide each participant with retirement benefits that are compara-
ble in value to those of similar retirement programs administered by other companies, as well as to align each participant’s supplemental
benefits under the SERP with the interests of our unitholders. All allocations made to participants under the SERP are made in the form of
“phantom” units. The SERP is administered by the compensation committee. Our managing general partner is able to amend or terminate
the plan at any time. Our managing general partner is entitled to reimbursement by us for its costs incurred under the SERP.

Compensation Committee’s Report on Executive Compensation

The compensation committee administers the executive compensation programs of our managing general partner and was estab-
lished to fulfill two purposes: (a) to discharge the board of directors’ responsibilities relating to compensation of our managing general part-
ner's directors and executives and (b) to produce an annual report on executive compensation for inclusion in our annual report on Form
10-K. All three members of the compensation committee of the board of directors (currently Mr. Miller, Mr. Neafsey and Mr. Robinson) are
“non-employee directors” as defined under the Securities Exchange Act of 1934 and the Internal Revenue Code. The board of directors has
assigned to the compensation committee the following functions:

• To review and approve corporate goals and objectives relative to our managing general partner's president and chief executive
officer's (CEO) compensation, and evaluate the CEO’s performance in light of those goals and objectives and to set the CEO’s
compensation level based on this evaluation.

• To review and approve corporate goals and objectives relative to our senior executive officers, including our named executive
officers’ compensation, evaluate our senior executive officers’ performance in light of those goals and objectives, and to set the
senior executive compensation levels based on this evaluation.

• To make recommendations to the board of directors with respect to incentive compensation plans and equity-based plans, includ-
ing, without limitation, our managing general partner's short-term incentive plan (STIP), long-term incentive plan (LTIP), and sup-
plemental executive retirement plan (SERP).

• To administer our managing general partner's LTIP and grant restricted units or other awards pursuant to such plan.

For the fiscal year ended December 31, 2004, the compensation committee met on five separate occasions and primarily focused its
activities on the primary elements of the total direct compensation program for executive officers; the merits of continuation of the LTIP;
the guidelines for the STIP pertaining to eligibility, minimum thresholds, target objectives, target results, target payout groups, the respec-
tive percentage targets and the payout formula.

Overall Executive Compensation Program

The goals of our managing general partner's executive compensation program are to align compensation with our managing general
partner's business objectives and performance and enable our managing general partner to attract, retain and motivate qualified executive
officers that contribute to the long-term success of our managing general partner and its affiliates. The primary components of our man-
aging general partner's executive compensation programs are:

• base salary;

• annual incentive bonus awards; and

• equity participation in the form of restricted units.

Executive officers are also entitled to customary benefits available to all of our managing general partner's employees, including

group medical, dental, and life insurance and participation in our managing general partner's profit sharing and savings plan.

Base Salary. The compensation committee reviews and recommends the base salary of our managing general partner's named executive
officers, as well as our other officers and key employees. When reviewing base salaries, the compensation committee considers the indi-
vidual’s performance, past performance of our managing general partner and the individual’s contribution to that performance, the individ-
ual’s level of responsibility and competitive pay practices. In general, base salaries are targeted at the middle of the competitive market
place. This assessment considers relevant industry salary practices, the position’s complexity and level of responsibility, its importance to
our managing general partner in relation to other executive positions, and the competitiveness of an executive’s total compensation.
Subject to the committee’s approval, the level of an executive officer’s base pay is determined on the basis of relative comparative com-
pensation data and the CEO’s assessment of the executive’s performance, experience, demonstrated leadership, job knowledge and man-
agement skills.

Annual Incentive Bonus Awards. To provide discretionary annual incentive bonus awards, our managing general partner maintains the
STIP. The purpose of the STIP is to enhance unitholder value by providing eligible employees, including executive officers of our managing
general partner, with added incentive to achieve specific annual targets. The STIP also assists our managing general partner in attracting,
retaining and motivating qualified personnel in order to allow our managing general partner to remain competitive with its industry peers.
The targets are intended to be aligned with our managing general partner's mission so that bonus payments are made only if unitholder
interests are advanced. These targets are established prior to the beginning of each fiscal year. Under the STIP and its related guidelines,
our managing general partner's executive officers and other employees selected by the compensation committee are eligible for cash
bonuses based upon the comparison of our actual performance results to an annual adjusted EBITDA target. Adjusted EBITDA is defined
as income before LTIP expense, net interest expense, income taxes and depreciation, depletion and amortization.

Each executive officer of our managing general partner participating in the STIP was eligible to earn a cash bonus expressed as a per-
centage of such officer’s base salary. The incentive bonus opportunities varied by each executive officer’s level of responsibility. In order
to calculate the annual aggregate cash bonus amount available for discretionary awards under the STIP for employees eligible to receive
such cash bonuses, the STIP provides a formula dependent on our actual adjusted EBITDA results for the year, based on a percentage of
each eligible employee’s base salary. For fiscal year 2004, we exceeded our annual adjusted EBITDA target so that all of the 2004 STIP par-
ticipants were eligible to receive a percentage of their salary as bonus awards at the discretion of the compensation committee and/or our
CEO. Bonuses are payable in the first quarter of the following calendar year.

Equity Participation. Equity compensation in the form of restricted units is a key component of our managing general partner's executive
compensation program. Under the LTIP administered by the compensation committee, annual grant levels for designated employees are
recommended by the CEO. The grants are made either of (a) restricted units, which are “phantom units” that entitle a grantee to receive a
common unit or at the discretion of our managing general partner an equivalent amount of cash upon the vesting of a phantom unit or (b)
options to purchase common units. Restricted units are vested over a stated period from the grant date. The issuance of the common units
pursuant to the LTIP is intended to serve as a means of incentive compensation performance and not primarily as an opportunity to partic-
ipate in the equity participation with respect to our common units. Therefore, no consideration will be payable by the plan participants upon
receipt of the common units. To date, the compensation committee has not granted any unit options under the LTIP.

CEO Executive Compensation. In determining Mr. Craft’s compensation, the compensation committee considered our financial perform-
ance and peer group compensation data as well as Mr. Craft’s leadership, decision-making skills, experience, knowledge, communication
with the board of directors and strategic recommendations. The compensation committee did not place any particular relative weight on
any one of these factors, but our financial performance is generally given the most weight. The committee’s decisions regarding Mr. Craft’s
compensation are reported to and discussed with the board of directors meeting in executive session without Mr. Craft’s participation. For
fiscal year 2004, Mr. Craft served as CEO of our managing general partner. Effective June 1, 2002, Mr. Craft's annual salary was increased
to $334,828 from $321,950, which adjustment was determined in the manner described above. The compensation committee honored Mr.
Craft's request that his salary not be increased in 2003 and 2004 even though a salary increase would have been warranted under the com-
pensation adjustment procedure described above. Differences in Mr. Craft’s annual salary as reported in the summary compensation table
above are attributable to the effective date of the salary adjustment in the year 2002 and the number of weekly pay periods in a calendar
year. Based on our record performance for 2004, Mr. Craft received a cash bonus (paid in fiscal year 2005) equal to approximately 112% of
his base salary.

Conclusion. Based upon its review of our managing general partner's overall executive compensation program, the compensation
committee has concluded that the program's structure is appropriate, competitive and effective to serve the purposes for which it was
established. Moreover, the compensation committee believes that the total compensation opportunities provided to our managing gener-
al partner's executive officers creates a commonality of interest and alignment with the long-term interests of both our managing general
partner and its unitholders.

Members of the Compensation Committee:

Preston R. (Jeff) Miller, Chairman

John H. Robinson

John P. Neafsey

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth certain information as of March 1, 2005, regarding the beneficial ownership of common units held by
(a) each person known by our managing general partner to be the beneficial owner of 5% or more of the common units, (b) each director
and executive officer of our managing general partner and (c) all directors and executive officers of our managing general partner as a
group. Our managing general partner is owned by members of management. Our special general partner is a wholly-owned subsidiary of
Alliance Resource Holdings. The address of Alliance Resource Holdings, our managing general partner and our special general partner is
1717 South Boulder Avenue, Tulsa, Oklahoma 74119.

Name of Beneficial Owner
Alliance Resource GP, LLC (1)
Joseph W. Craft III (1)(4)
Robert G. Sachse (1)
Thomas L. Pearson (1)
Charles R. Wesley (1)
Brian L. Cantrell (1)
Gary J. Rathburn (1)
Michael J. Hall (1)
John J. MacWilliams (2)
Preston R. Miller, Jr. (2)
John P. Neafsey (1)
John H. Robinson (3)
All directors and executive officers as a group (9 persons)
* Less than one percent

Common Units
Beneficially Owned (5)
7,655,311
7,952,691
12,296
18,920
44,129
1,167
18,071
10,625
654
654
19,271
6,653
8,085,131

Percentage of Common Units
Beneficially Owned
42.22%
43.86%
*
*
*
*
*
*
*
*
*
*
44.59%

(1) The address of Alliance Resource GP, LLC and Messrs. Craft, Sachse, Pearson, Wesley, Cantrell, Rathburn, Hall, and Neafsey is

1717 South Boulder Avenue, Tulsa, Oklahoma 74119.

(2) The address of Mr. MacWilliams and Mr. Miller is The Tremont Group, LLC., 275 Grove St., Suite 2-400, Newton, Massachusetts 02466.

(3) The address of Mr. Robinson is 121 West 48th Street, Suite 1006, Kansas City, Missouri 64112.

(4) Mr. Craft may be deemed to share beneficial ownership of 7,655,311 common units held by Alliance Resource GP, LLC through Alliance
Resource Holdings II, Inc., of which he is the sole director and majority shareholder. Alliance Resource Holdings II holds all
of the outstanding shares of Alliance Resource Holdings, Inc., which holds all of the outstanding shares of Alliance Resource GP. Mr.
Craft may be deemed to share beneficial ownership of 110,242 common units held by AMH II, LLC, of which he is the sole director
and majority member. Mr. Craft may be deemed to share beneficial ownership of 9,761 common units held by Alliance Management
Holdings, LLC, of which he is the sole director. Mr. Craft may also be deemed to share beneficial ownership of an additional 13,500
common units held by a private foundation for which he serves as a Trustee. Mr. Craft disclaims beneficial ownership of the common
units held by the private foundation.

(5) The amounts set forth do not include any restricted units granted under the LTIP which vest at various dates ranging from September

30, 2005 through January 1, 2008, subject to certain financial tests.

Equity Compensation Plan Information

Plan Category

Equity compensation plans
approved by unitholders:
Long-Term Incentive Plan

Equity compensation plans not
approved by unitholders:
Supplemental Executive

Retirement Plan

Deferred Compensation

Plan for Directors

Number of units to be issued upon
exercise/vesting of outstanding
options, warrants and rights
as of March 1, 2005

Weighted-average exercise
price of outstanding
options, warrants and rights

Number of units remaining
available for future issuance
under equity compensation
plans as of March 1, 2005

298,420

49,929

17,970

N/A

70,454

30,071

32,030

For a description of our Supplemental Executive Retirement Plan and our Deferred Compensation Plan for Directors, please read

“Supplemental Executive Retirement Plan” and “Compensation of Directors” under “Item 11. Executive Compensation.”

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Certain Relationships and Related Transactions

Our special general partner owns 7,655,311 common units representing an aggregate 42.2% limited partner interest in us. In addi-
tion, our general partners own, on a combined basis, an aggregate 2% general partner interest in us, the intermediate partnership and the
subsidiaries. Our managing general partner's ability, as managing general partner, to control us together with our special general partner's
ownership of 7,655,311 common units, effectively gives our general partners the ability to veto some of our actions and to control our
management.

Transactions Between the Partnership, Special General Partner and Alliance Resource Holdings

Related Party Transactions

Administrative Services. Our partnership agreement provides that our managing general partner and its affiliates be reimbursed for all
direct and indirect expenses they incur or payments they make on our behalf including, but not limited to, management’s salaries and
related benefits (including incentive compensation), and accounting, budget, planning, treasury, public relations, land administration, envi-
ronmental, permitting, payroll, benefits, disability, workers’ compensation management, legal and information technology services. Our
managing general partner may determine in its sole discretion the expenses that are allocable to us. Total costs billed by our managing
general partner and its affiliates to us were approximately $28,536,000, $12,471,000, and $6,559,000 for the years ended December 31,
2004, 2003, and 2002, respectively. The increases from 2003 to 2004 and 2002 to 2003 were primarily attributable to higher accruals
related to common unit based incentive plans, which were impacted by the increased market value of our common units, and the STIP.

Warrior Acquisition. On February 14, 2003, we acquired Warrior from an affiliate, ARH Warrior Holdings a subsidiary of Alliance
Resource Holdings, pursuant to a Put/Call Agreement. Warrior purchased the capital stock of Roberts Bros. Coal Co., Inc., Warrior Coal
Mining Company, Warrior Coal Corporation and certain assets of Christian Coal Corp. and Richland Mining Co., Inc. in January 2001. Our
managing general partner had previously declined the opportunity to purchase these assets as we had previously committed to major cap-
ital expenditures at two existing operations. As a condition to not exercising its right of first refusal, we requested that ARH Warrior
Holdings enter into a put and call arrangement for Warrior. We and ARH Warrior Holdings, with the approval of the conflicts committee of
our managing general partner, entered into the Put/Call Agreement in January 2001. Concurrently, ARH Warrior Holdings acquired Warrior
in January 2001 for $10.0 million.

The put option price of $12.7 million was paid to ARH Warrior Holdings in accordance with the terms of the Put/Call Agreement. In
addition, we repaid Warrior’s borrowings of $17.0 million under the revolving credit agreement between our special general partner and
Warrior. The primary borrowings under the revolving credit agreement financed new infrastructure capital projects at Warrior that have
contributed to improved productivity and significantly increased capacity. We funded the Warrior acquisition through a portion of the pro-
ceeds received from the issuance of 2,250,000 common units. Because the Warrior acquisition was between entities under common con-
trol, it has been accounted for at historical cost in a manner similar to that used in a pooling of interests.

Under the terms of the mineral lease and sublease agreements described above, Dotiki and Warrior also reimbursed SGP Land for
SGP Land's base lease obligations. We reimbursed SGP Land $5,428,000, $4,395,000, and $3,922,000 for the years ended December 31,
2004, 2003 and 2002 respectively, for the base lease obligations. Dotiki and Warrior have recouped as earned royalties all advance mini-
mum royalty payments made in accordance with these terms except for $216,000 as of December 31, 2004.

We have previously entered into and have maintained agreements with two banks to provide letters of credit in an aggregate amount
of $25.0 million to maintain surety bonds to secure our obligations for reclamation liabilities and workers’ compensation benefits. At
December 31, 2004, we had $22.2 million in outstanding letters of credit. Our special general partner guarantees these letters of credit.
Historically, we have compensated our special general partner a guarantee fee equal to 0.30% per annum of the face amount of the let-
ters of credit outstanding. Our special general partner agreed to waive the guarantee fee in exchange for a parent guarantee from our inter-
mediate partnership and Alliance Coal on the mineral lease and sublease with Dotiki and Warrior. We paid approximately $31,300 and
$48,200 in guarantee fees to our special general partner for the years ended December 31, 2003 and 2002, respectively.

Elk Creek and Tunnel Ridge. On October 21, 2004, we announced an agreement, subject to finalization of definitive agreements, to enter
into two separate coal leases, which cumulatively will increase our coal reserve holdings by 25%. The Elk Creek reserves are located in
Hopkins County, Kentucky, and the Tunnel Ridge reserves are located in Ohio County, West Virginia and Washington County, Pennsylvania.
These leases are estimated to contain approximately 100 million tons of high-sulfur coal reserves. The lessor for both leases is our special
general partner. We also announced plans to immediately begin the development process for these properties, which includes obtaining
the necessary mining permits and securing sufficient coal sales commitments to justify the capital investment needed to bring these
properties into production.

The Elk Creek reserve area encompasses approximately 9,000 acres and is contiguous to our Hopkins County Coal complex. The Elk
Creek coal reserves are currently estimated to include approximately 30 million tons of high-sulfur coal. The Elk Creek mine will be an
underground mining complex, that mines the West Kentucky No. 9 and No. 11 coal seams. It will utilize continuous mining units and employ
room-and-pillar mining techniques. We intend to use the existing coal handling and other surface facilities owned by Hopkins County Coal.
We anticipate the Elk Creek complex will employ as many as 250 individuals and produce up to 3.2 million tons of coal annually. We esti-
mate total capital expenditures to develop Elk Creek to be approximately $65.0 million. In December, 2004, the board of directors of our
managing general partner approved the capital expenditures associated with Elk Creek. Coal supply commitments are currently being pur-
sued. Construction of the Elk Creek mining complex began in the first quarter of 2005. We expect to fund these capital expenditures with
available cash and marketable securities on hand, future cash generated from operations and borrowings available under our revolving
credit facility.

In January 2005, we acquired 100% of the limited liability company member interests of Tunnel Ridge, LLC for approximately $500,000
and the assumption of reclamation liabilities from Alliance Resource Holdings, Inc., a company owned by our management. Tunnel Ridge,
LLC controls through a coal lease agreement with the special general partner an estimated 70 million tons of high-sulfur coal in the
Pittsburgh No. 8 coal seam. The Tunnel Ridge reserve area encompasses approximately 50,571 acres of land located in Ohio County, West
Virginia and Washington County, Pennsylvania. Under the terms of the coal lease, beginning on January 1, 2005, Tunnel Ridge, LLC began
paying our special general partner an advance minimum royalty of $3.0 million per year, which advance royalty payments will be fully
recoupable against earned royalties. The earned royalty rate under the coal lease is the greater of $0.75 per ton or 3.0% of the per ton
gross sales price f.o.b. barge. The term of the coal lease is the earlier of 30 years or until exhaustion of all mineable and merchantable
coal with termination rights after the initial four years of the coal lease.

Tunnel Ridge, LLC also controls, under a separate lease agreement with our special general partner, the rights to approximately 900
acres of surface land and other tangible assets. Under the terms of the lease agreement, Tunnel Ridge, LLC shall pay our special general
partner an annual lease payment of $240,000 beginning January 1, 2005. The lease agreement has an initial term of four years, which term
may be extended by Tunnel Ridge, LLC at the same annual lease payment rate, to be consistent with the term of the coal lease.

The Elk Creek and Tunnel Ridge transactions described above are related-party transactions and, as such, were reviewed by the board
of directors of our managing general partner and its conflicts committee. Based upon these reviews, it was determined that these trans-
actions reflect market-clearing terms and conditions customary in the coal industry. As a result, the board of directors of our managing gen-
eral partner and its conflicts committee approved the Elk Creek and Tunnel Ridge transactions as fair and reasonable to us.

Other Related Party Transactions

None.

Omnibus Agreement

Concurrently with the closing of our initial public offering, we entered into an omnibus agreement with Alliance Resource Holdings
and our general partners, which govern potential competition among us and the other parties to this agreement. The omnibus agreement
was amended in May 2002. Pursuant to the terms of the amended omnibus agreement, Alliance Resource Holdings agreed, and caused its
controlled affiliates to agree, for so long as management controls our managing general partner, not to engage in the business of mining,
marketing or transporting coal in the U.S. unless it first offers us the opportunity to engage in a potential activity or acquire a potential
business, and the board of directors of our managing general partner, with the concurrence of its conflicts committee, elects to cause us
not to pursue such opportunity or acquisition. In addition, Alliance Resource Holdings has the ability to purchase businesses, the majority
value of which is not mining, marketing or transporting coal, provided Alliance Resource Holdings offers us the opportunity to purchase the
coal assets following their acquisition. The restriction does not apply to the assets retained and business conducted by Alliance Resource
Holdings at the closing of our initial public offering. Except as provided above, Alliance Resource Holdings and its controlled affiliates are

prohibited from engaging in activities wherein they compete directly with us. In addition to its non-competition provisions, this agreement
contains provisions which indemnify us against liabilities associated with certain assets and businesses of Alliance Resource Holdings
which were disposed of or liquidated prior to consummating our initial public offering.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The firm of Deloitte & Touche LLP is our independent registered public accounting firm. Fees paid to Deloitte & Touche LLP during the

last two fiscal years were as follows:

Audit Services. Fees for audit services provided during the years ended December 31, 2004 and 2003, were
$745,000 and $240,000, respectively. Audit services consist primarily of the audit and quarterly reviews of the consol-
idated financial statements, but can also be related to statutory audits of subsidiaries required by governmental or
regulatory bodies, attestation services required by statute or regulation, comfort letters, consents, assistance with
and review of documents filed with the SEC, work performed by tax professionals in connection with the audit and
quarterly reviews, and accounting and financial reporting consultations and research work necessary to comply with
generally accepted accounting principles.

Audit-Related Services. Fees for audit-related services provided during the years ended December 31, 2004 and
2003, were $18,500 and $36,000, respectively. Audit-related services consist primarily of audits of employee benefit
plans, consultations concerning financial accounting and reporting standards, and attestation services associated
with third-party compliance.

Tax Services. Fees for tax services provided during the years ended December 31, 2004 and 2003, were $180,000
and $231,000, respectively. Tax services relate primarily to the preparation of federal and state tax returns but can
also be related to tax advice, exclusive of tax services rendered in conjunction with the audit.

All Other Fees. In 2004, fees for due diligence services provided in conjunction with a proposed investment were

$72,000. There were no other fees during the year ended December 31, 2003.

The charter of the audit committee provides that the committee is responsible for the pre-approval of all auditing services and
permitted non-audit services to be performed for us by our independent registered public accounting firm, subject to the requirements of
applicable law. In accordance with such charter, the audit committee may delegate the authority to grant such pre-approvals to the audit
committee chairman or a sub-committee of the audit committee, which pre-approvals are then reviewed by the full audit committee at its
next regular meeting. Typically, however, the audit committee itself reviews the matters to be approved. The audit committee periodically
monitors the services rendered by and actual fees paid to the independent registered public accounting firm to ensure that such services
are within the parameters approved by the audit committee.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) (1)

Financial Statements.

The response to this portion of Item 15 is submitted as a separate section herein under Part II, Item 8. – Financial Statements
and Supplementary Data.

(a)(2) Financial Statement Schedules.

Schedule II – Valuation and Qualifying Accounts – Years ended December 31, 2004, 2003 and 2002, is set forth under Part II
Item 8. - Financial Statements and Supplementary Data. All other schedules are omitted because they are not applicable or the
information is shown in the financial statements or notes thereto.

(a)(3) and (c) The exhibits listed below are filed as part of this annual report.

3.1

3.2

3.3

3.4

3.5

3.6

3.7

3.8

4.1

Amended and Restated Agreement of Limited Partnership of Alliance Resource Partners, L.P. (Incorporated by ref-
erence to Exhibit 3.1 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1999, File No.
000-26823).

Amended and Restated Agreement of Limited Partnership of Alliance Resource Operating Partners, L.P. (Incorporated
by reference to Exhibit 3.2 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1999,
File No. 000-26823).

Certificate of Limited Partnership of Alliance Resource Partners, L.P. (Incorporated by reference to Exhibit 3.6 of the
Registrant’s Registration Statement on Form S-1 filed with the Commission on May 20, 1999 (Reg. No. 333-78845)).

Certificate of Limited Partnership of Alliance Resource Operating Partners, L.P. (Incorporated by reference to Exhibit
3.8 of the Registrant’s Registration Statement on Form S-1/A filed with the Commission on July 20, 1999 (Reg. No.
333-78845)).

Certificate of Formation of Alliance Resource Management GP, LLC (Incorporated by reference to Exhibit 3.7 of the
Registrant’s Registration Statement on Form S-1/A filed with the Commission on July 23, 1999 (Reg. No. 333-78845)).

Amended and Restated Operating Agreement of Alliance Resource Management GP, LLC (Incorporated by reference
to Exhibit 3.4 of the Registrant’s Registration Statement on Form S-3 filed with the Commission on April 1, 2002
(Reg. No. 333-85282)).

Amendment No. 1 to Amended and Restated Operating Agreement of Alliance Resource Management GP, LLC (Incor-
porated by reference to Exhibit 3.5 of the Registrant’s Registration Statement on Form S-3 filed with the Commission
on April 1, 2002 (Reg. No. 333-85282)).

Amendment No. 2 to Amended and Restated Operating Agreement of Alliance Resource Management GP, LLC (Incor-
porated by reference to Exhibit 3.6 of the Registrant’s Registration Statement on Form S-3 filed with the Commission
on April 1, 2002 (Reg. No. 333-85282)).

Form of Common Unit Certificate (Included as Exhibit A to the Amended and Restated Agreement of Limited Partner-
ship of Alliance Resource Partners, L.P.)

100

10.1

10.2

10.3

10.4

10.5

10.6

10.7

10.8

10.9

10.10

10.11

10.12

10.13

Credit Agreement, dated as of August 22, 2003, among Alliance Resource Operating Partners, L.P., JPMorgan Chase
Bank (as paying agent), Citicorp USA, Inc. and JPMorgan Chase Bank (as co-administrative agents) and lenders named
therein. (Incorporated by reference to Exhibit 10.41 of the Registrant’s Quarterly Report on Form 10-Q for the quarter
ended September 30, 2003, File No. 000-26823).

Note Purchase Agreement, dated as of August 16, 1999, among Alliance Resource GP, LLC and the purchasers named
therein. (Incorporated by reference to Exhibit 10.20 of the Registrant’s Annual Report on Form 10-K for the year ended
December 31, 1999, File No. 000-26823).

Letter of Credit Facility Agreement dated as of June 29, 2001, between Alliance Resource Partners, L.P. and Bank of
Oklahoma, National Association. (Incorporated by reference to Exhibit 10.20 of the Registrant’s Quarterly Report on
Form 10-Q for the quarter ended September 30, 2001, File No. 000-26823).

Amendment One to Letter of Credit Facility Agreement between Alliance Resource Partners, L.P. and Bank of Okla-
homa, National Association. (Incorporated by reference to Exhibit 10.33 of the Registrant’s Quarterly Report on
Form 10-Q for the quarter ended September 30, 2002, File No. 000-26823).

Promissory Note Agreement dated as of July 31, 2001, between Alliance Resource Partners, L.P. and Bank of Okla-
homa, N. A. (Incorporated by reference to Exhibit 10.21 of the Registrant’s Quarterly Report on Form 10-Q for the
quarter ended September 30, 2001, File No. 000-26823).

Guarantee Agreement, dated as of July 31, 2001, between Alliance Resource GP, LLC and Bank of Oklahoma, N.A.
(Incorporated by reference to Exhibit 10.22 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended
September 30, 2001, File No. 000-26823).

Letter of Credit Facility Agreement dated as of August 30, 2001, between Alliance Resource Partners, L.P. and Fifth
Third Bank. (Incorporated by reference to Exhibit 10.23 of the Registrant’s Quarterly Report on Form 10-Q for the
quarter ended September 30, 2001, File No. 000-26823).

Amendment No. 1 to Letter of Credit Facility Agreement between Alliance Resource Partners, L.P. and Fifth Third Bank.
(Incorporated by reference to Exhibit 10.9 of the Registrant's Annual Report on Form 10-K for the year ended
December 31, 2002, File No. 000-26823).

Guarantee Agreement, dated as of August 30, 2001, between Alliance Resource GP, LLC and Fifth Third Bank. (Incor-
porated by reference to Exhibit 10.24 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended Sep-
tember 30, 2001, File No. 000-26823).

Letter of Credit Facility Agreement dated as of October 2, 2001, between Alliance Resource Partners, L.P. and Bank
of the Lakes, National Association. (Incorporated by reference to Exhibit 10.25 of the Registrant’s Quarterly Report
on Form 10-Q for the quarter ended September 30, 2001, File No. 000-26823).

First Amendment to the Letter of Credit Facility Agreement between Alliance Resource Partners, L.P. and Bank of
the Lakes, National Association. (Incorporated by reference to Exhibit 10.32 of the Registrant’s Quarterly Report on
Form 10-Q for the quarter ended September 30, 2002, File No. 000-26823).

Promissory Note Agreement dated as of October 2, 2001, between Alliance Resource Partners, L.P. and Bank of the
Lakes, N.A. (Incorporated by reference to Exhibit 10.26 of the Registrant’s Quarterly Report on Form 10-Q for the
quarter ended September 30, 2001, File No. 000-26823).

Guarantee Agreement, dated as of October 2, 2001, between Alliance Resource GP, LLC and Bank of the Lakes, N.A.
(Incorporated by reference to Exhibit 10.27 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended
September 30, 2001, File No. 000-26823).

101

10.14

10.15

10.16

10.17

10.18

10.19

10.20

10.21

10.22

10.23

10.24

10.25

Guaranty Fee Agreement dated as of July 31, 2001, between Alliance Resource Partners, L.P. and Alliance Resource
GP, LLC. (Incorporated by reference to Exhibit 10.28 of the Registrant’s Quarterly Report on Form 10-Q for the quarter
ended September 30, 2001, File No. 000-26823).

Contribution and Assumption Agreement, dated August 16, 1999, among Alliance Resource Holdings, Inc., Alliance
Resource Management GP, LLC, Alliance Resource GP, LLC, Alliance Resource Partners, L.P., Alliance Resource
Operating Partners, L.P. and the other parties named therein. (Incorporated by reference to Exhibit 10.3 of the
Registrant’s Annual Report on Form 10-K for the year ended December 31, 1999, File No. 000-26823).

Omnibus Agreement, dated August 16, 1999, among Alliance Resource Holdings, Inc., Alliance Resource Manage-
ment GP, LLC, Alliance Resource GP, LLC and Alliance Resource Partners, L.P. (Incorporated by reference to Exhibit
10.4 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1999, File No. 000-26823).

Amended and Restated Alliance Resource Management GP, LLC 2000 Long-Term Incentive Plan. (Incorporated by ref-
erence to Exhibit 10.17 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2003, File
No. 000-26823).

First Amendment to the Alliance Resource Management GP, LLC 2000 Long-Term Incentive Plan. (Incorporated by re-
ference to Exhibit 10.18 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2003, File
No. 000-26823).

Alliance Resource Management GP, LLC Short-Term Incentive Plan. (Incorporated by reference to Exhibit 10.12 of
the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1999, File No. 000-26823).

Alliance Resource Management GP, LLC Supplemental Executive Retirement Plan. (Incorporated by reference to
Exhibit 99.2 of the Registrant’s Registration Statement on Form S-8 filed with the Commission on April 1, 2002
(Reg. No. 333-85258)).

Alliance Resource Management GP, LLC Deferred Compensation Plan for Directors. (Incorporated by reference to
Exhibit 99.3 of the Registrant’s Registration Statement on Form S-8 filed with the Commission on April 1, 2002
(Reg. No. 333-85258)).

Restated and Amended Coal Supply Agreement, dated February 1, 1986, among Seminole Electric Cooperative, Inc.,
Webster County Coal Corporation and White County Coal Corporation. (Incorporated by reference to Exhibit 10.9 of
the Registrant’s Registration Statement on Form S-1/A filed with the Commission on July 20, 1999 (Reg. No.
333-78845)).

Amendment No. 1 to the Restated and Amended Coal Supply Agreement effective April 1, 1996, between MAPCO
Coal Inc., Webster County Coal Corporation, White County Coal Corporation, and Seminole Electric Cooperative, Inc.
(Incorporated by reference to Exhibit 10.14 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended
June 30, 2000, File No. 000-26823).

Amendment No. 2 to the Restated and Amended Coal Supply Agreement effective February 28, 2002 between Web-
ster County Coal, LLC, White County Coal, LLC, and Seminole Electric Cooperative, Inc. (Incorporated by reference to
Exhibit 10.32 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 000-
26823).

Amendment No. 3 to the Restated and Amended Coal Supply Agreement effective January 1, 2003 between Web-
ster County Coal, LLC, White County Coal, LLC, Alliance Coal, LLC, and Seminole Electric Cooperative, Inc. (Incorpor-
ated by reference to Exhibit 10.39 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31,
2003, File No. 000-26823).

102

10.26

10.27

10.28

10.29

10.30

10.31

10.32

10.33

10.34

10.35

10.36

10.37

10.38

Interim Coal Supply Agreement effective May 1, 2000, between Alliance Coal, LLC and Seminole Electric Coopera-
tive, Inc. (Incorporated by reference to Exhibit 10.15 of the Registrant’s Quarterly Report on Form 10-Q for the quar-
ter ended June 30, 2000, File No. 000-26823).

Agreement for Supply of Coal to the Mt. Storm Power Station, dated January 15, 1996, between Virginia Electric and
Power Company and Mettiki Coal Corporation. (Incorporated by reference to Exhibit 10. (t) to MAPCO Inc.’s Annual
Report on Form 10-K, filed April 1, 1996, File No. 1-5254).

Memorandum of Understanding dated January 17, 2005 between VEPCO and Mettiki. (Incorporated by reference to
Exhibit 10.2 of the Registrants Form 8-K filed with the Commission on January 19, 2005, File No. 000-26823).

Amendment No. 1 dated January 17, 2005 between VEPCO and Mettiki to the Coal Supply Agreement. (Incorporated
by reference to Exhibit 10.2 of the Registrants Form 8-K filed with the Commission on January 19, 2005, File No. 000-
26823).

Coal Feedstock Supply Agreement dated October 26, 2001, between Synfuel Solutions Operating LLC and Hopkins
County Coal, LLC (Incorporated by reference to Exhibit 10.27 of the Registrant’s Annual Report on Form 10-K for the
year ended December 31, 2001, File No. 000-26823).

First Amendment to Coal Feedstock Supply Agreement dated February 28, 2002, between Synfuel Solutions Operating
LLC and Hopkins County Coal, LLC (Incorporated by reference to Exhibit 10.28 of the Registrant’s Annual Report on
Form 10-K for the year ended December 31, 2001, File No. 000-26823).

Second Amendment to Coal Feedstock Supply Agreement dated April 1, 2003, between Synfuel Solutions Operating
LLC and Warrior Coal, LLC. (Incorporated by reference to Exhibit 10.40 of the Registrant's Quarterly Report on Form
10-Q for the quarter ended June 30, 2003, File No. 000-26823).

Assignment and Assumption Agreement dated April 1, 2003 between Synfuel Solutions Operating LLC, Hopkins
County Coal, LLC, and Warrior Coal, LLC. (Incorporated by reference to Exhibit 10.31 of the Registrant's Annual
Report on Form 10-K for the year ended December 31, 2003, File No. 000-26823).

Amended and Restated Put and Call Option Agreement dated February 12, 2001 between ARH Warrior Holdings, Inc.
and Alliance Resource Partners, L.P. (Incorporated by reference to Exhibit 10.17 of the Registrant’s Annual Report on
Form 10-K for the year ended December 31, 2000, File No. 000-26823).

Letter Agreement dated January 31, 2003 between ARH Warrior Holdings, Inc. and Alliance Resource Partners, L.P.
(Incorporated by reference to Exhibit 10.34 of the Registrant’s Annual Report on Form 10-K for the year ended Dec-
ember 31, 2002 File No. 000-26823).

Consulting Agreement for Mr. Sachse dated January 1, 2001. (Incorporated by reference to Exhibit 10.18 of the Reg-
istrant’s Annual Report on Form 10-K for the year ended December 31, 2000, File No. 000-26823).

Extension of Consulting Agreement with Mr. Sachse, dated September 30, 2003. (Incorporated by
to
Exhibit 10.42 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No.
000-26823).

reference

Form of Employee Agreements for Messrs. Craft, Pearson, Wesley and Rathburn. (Incorporated by reference to
Exhibit 10.6 of the Registrant’s Registration Statement on Form S–1/A filed with the Commission on August 9, 1999
(Reg. No. 333-78845)).

103

10.39

Security and Pledge Agreement dated as of May 8, 2002 by and among Alliance Resource Holdings II, Inc., AMH II,
LLC, Alliance Resource Holdings, Inc., Alliance Resource GP, LLC, the Management Investors as identified therein,
The Beacon Group Energy Investment Fund, L.P., MPC Partners, LP and three individuals as “Sellers” identified therein,
and JPMorgan Chase Bank as collateral agent. (Incorporated by reference to Exhibit 99.2 of the Registrant’s
Form 8-K filed with the Commission on May 9, 2002, File No. 000-26823).

10.40

Form of Promissory Note made by Alliance Resource Holdings, Inc. dated as of May 8, 2002. (Incorporated by re-
ference to Exhibit 99.3 of the Registrant’s Form 8-K filed with the Commission on May 9, 2002, File No. 000-26823).

*10.41

Amended and Restated Charter for the Audit Committee of the Board of Directors dated March 10, 2005.

18.1

Preferability Letter on Accounting Change. (Incorporated by reference to Exhibit 18.1 of the Registrant’s Amended
Quarterly Report on Form 10-Q/A for the quarter ended March 31, 2001, File No. 000-26823).

* 21.1

List of Subsidiaries

* 23.1

* 31.1

* 31.2

* 32.1

* 32.2

Consent of Deloitte & Touche LLP regarding Form S-3 and Form S-8, Registration No. 333-85282 and No. 333-85258,
respectively.

Certification of Joseph W. Craft III, President and Chief Executive Officer of Alliance Resource Management GP, LLC,
the managing general partner of Alliance Resource Partners, L.P., dated March 15, 2005, pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002 furnished herewith.

Certification of Brian L. Cantrell, Senior Vice President and Chief Financial Officer of Alliance Resource Management
GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated March 15, 2005, pursuant to Section
302 of the Sarbanes-Oxley Act of 2002 furnished herewith.

Certification of Joseph W. Craft III, President and Chief Executive Officer of Alliance Resource Management GP, LLC,
the managing general partner of Alliance Resource Partners, L.P., dated March 15, 2005, pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002 furnished herewith.

Certification of Brian L. Cantrell, Senior Vice President and Chief Financial Officer of Alliance Resource Management
GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated March 15, 2005, pursuant to Section
906 of the Sarbanes-Oxley Act of 2002 furnished herewith.

* Filed herewith.

104

Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its

behalf by the undersigned thereunto duly authorized, in Tulsa, Oklahoma, on March 15, 2005.

ALLIANCE RESOURCE PARTNERS, L.P.

By: Alliance Resource Management GP, LLC
its managing general partner

/s/ Joseph W. Craft III
Joseph W. Craft III
President, Chief Executive
Officer and Director

/s/ Brian L. Cantrell
Brian L. Cantrell
Senior Vice President and
Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on

behalf of the registrant and in the capacities and on the dates indicated.

Signature

Title

/s/ Joseph W. Craft III
Joseph W. Craft III

President, Chief Executive Officer
and Director (Principal Executive Officer)

Senior Vice President and
Chief Financial Officer

Director

/s/ Brian L. Cantrell
Brian L. Cantrell

/s/ Michael J. Hall
Michael J. Hall

/s/ John J. MacWilliams
John J. MacWilliams

/s/ Preston R. Miller, Jr.
Preston R. Miller, Jr.

/s/ John P. Neafsey
John P. Neafsey

/s/ John H. Robinson
John H. Robinson

/s/ Robert G. Sachse
Robert G. Sachse

Executive Vice President and Director

March 15, 2005

Date

March 15, 2005

Unitholder Information

PUBLICLY-TRADED UNITS
Alliance Resource Partners, L.P. is a pub-
licly traded master limited partnership.
Alliance Resource Partners, L.P. common
units began trading on the NASDAQ
National Market under the symbol “ARLP”
in August 1999. As of December 31, 2004,
there were 18,130,440 common and
subordinated units outstanding.

CASH DISTRIBUTIONS
Alliance Resource Partners, L.P. expects to
make Quarterly Distributions within 45
days after the end of each March, June,
September and December to unitholders
of record on the applicable record dates.

PARTNERSHIP TAX DETAILS
• Unitholders are partners in the Partnership
and receive cash distributions. The cash
distributions are generally not taxable as
long as the unitholder’s tax basis remains
above zero.

• A partnership is generally not subject to
federal or state income tax. The annual
income, gains, losses, deductions or
credits of the Partnership flow through
to the unitholders, who are required to
report their allocated share of these
amounts on their individual tax returns,
as though the unitholder had incurred
these items directly.

• Unitholders of record will receive

Schedule K-1 packages that summarize

their allocated share of the Partnership’s
reportable tax items for the fiscal year.
It is important to note that cash distribu-
tions received should not be reported
as taxable income. Only the amounts
provided on the Schedule K-1 should
be entered on each unitholder’s 2004
tax return.

• Should you have questions regarding

the Schedule K-1 contact:
Alliance Resource Partners, L.P.
K-1 Support
P.O. Box 480927
Denver, CO 80248
(800) 485-6875
Fax: (720) 931-7937

TRANSFER AGENT AND REGISTRAR
Unitholder requests regarding transfer of
units, lost certificates, lost distribution
checks or changes of address should be
directed to:
American Stock Transfer
and Trust Company
Attn: Shareholder Services
59 Maiden Lane-Plaza Level
New York, NY 10038
(800) 937-5449

ADDITIONAL INVESTOR INFORMATION
Additional information about Alliance
Resource Partners, L.P. can be obtained
by contacting Investor Relations by
e-mail at investorrelations@arlp.com,
telephone at (918) 295-7674, visiting the
Partnership’s website at www.arlp.com,
or writing to the Partnership’s mailing
address provided below.

PARTNERSHIP OFFICES
Alliance Resource Partners, L.P.
1717 South Boulder Avenue
Tulsa, OK 74119
(918) 295-7600

PARTNERSHIP MAILING ADDRESS
P.O. Box 22027
Tulsa, OK 74121-2027

INDEPENDENT AUDITORS
Deloitte & Touche LLP
Two Warren Place
6120 South Yale Suite 1700
Tulsa, OK 74136

CONTACT
Brian L. Cantrell
Senior Vice President and
Chief Financial Officer
(918) 295-7674
brian.cantrell@arlp.com

ALLIANCE RESOURCE PARTNERS, L.P. common units are traded on
the NASDAQ National Market under the ticker symbol “ARLP.”

OFFICERS AND DIRECTORS
Joseph W. Craft III
President, Chief Executive Officer
and Director

Robert G. Sachse
Executive Vice President and
Vice Chairman of the Board

Thomas L. Pearson
Senior Vice President – Law and
Administration, General Counsel
and Secretary

Charles R. Wesley
Senior Vice President – Operations

Brian L. Cantrell
Senior Vice President and
Chief Financial Officer

Gary J. Rathburn
Senior Vice President – Marketing

Michael J. Hall
Director

John J. MacWilliams
Director

Preston R. Miller, Jr.
Director

John P. Neafsey
Chairman of the Board

John H. Robinson
Director

P.O. BOX 22027
TULSA, OKLAHOMA 74121-2027
www.arlp.com