Alliance Resource Partners LP: Form 10-Q for the period ended Sep 30, 2011

Significant relationships referenced in this management’s discussion and analysis of financial condition and results of operations include the following:

• References to “we,” “us,” “our” or “ARLP Partnership” mean the business and operations of Alliance Resource Partners, L.P., the parent company, as well as its consolidated subsidiaries.
• References to “ARLP” mean Alliance Resource Partners, L.P., individually as the parent company, and not on a consolidated basis.
• References to “MGP” mean Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., also referred to as our managing general partner.
• References to “SGP” mean Alliance Resource GP, LLC, the special general partner of Alliance Resource Partners, L.P., also referred to as our special general partner.
• References to “Intermediate Partnership” mean Alliance Resource Operating Partners, L.P., the intermediate partnership of Alliance Resource Partners, L.P., also referred to as our intermediate partnership.
• References to “Alliance Coal” mean Alliance Coal, LLC, the holding company for the operations of Alliance Resource Operating Partners, L.P., also referred to as our operating subsidiary.
• References to “AHGP” mean Alliance Holdings GP, L.P., individually as the parent company, and not on a consolidated basis.
• References to “AGP” mean Alliance GP, LLC, the general partner of Alliance Holdings GP, L.P.

Summary

We are a diversified producer and marketer of coal primarily to major United States (“U.S.”) utilities and industrial users. We began mining operations in 1971 and, since then, have grown through acquisitions and internal development to become the fourth largest coal producer in the eastern U.S. We operate nine underground mining complexes in Illinois, Indiana, Kentucky, Maryland and West Virginia. We are constructing a new mining complex in West Virginia, and we also operate a coal loading terminal on the Ohio River at Mt. Vernon, Indiana. In addition, on July 25, 2011, the board of directors of our managing general partner (“Board of Directors”) approved development of a new mine in Indiana. As is customary in the coal industry, we have entered into long-term coal supply agreements with many of our customers.

We have four reportable segments: Illinois Basin, Central Appalachia, Northern Appalachia and Other and Corporate. The first three reportable segments correspond to the three major coal producing regions in the eastern U.S. Factors similarly affecting financial performance of our operating segments within each of these three reportable segments include coal quality, coal seam height, mining and transportation methods and regulatory issues.

• Illinois Basin reportable segment is comprised of multiple operating segments, including Webster County Coal, LLC’s Dotiki mining complex (“Dotiki”), Gibson County Coal, LLC’s Gibson North mining complex (“Gibson North”), Hopkins County Coal, LLC’s Elk Creek mining complex (“Hopkins”), White County Coal, LLC’s Pattiki mine (“Pattiki”), Warrior Coal, LLC’s mining complex (“Warrior”), River View Coal, LLC’s mining complex (“River View”), the Sebree Mining, LLC (“Sebree”) property, the Gibson County Coal (South), LLC (“Gibson South”) property and certain properties of Alliance Resource Properties, LLC (“Alliance Resource Properties”) and its wholly-owned subsidiary, ARP Sebree, LLC. We recently received the permits necessary to begin mine construction at the Gibson South property, and on July 25, 2011, the Board of Directors approved development of this mine, which is currently underway. We are in the process of permitting the Sebree property for future mine development.
• Central Appalachian reportable segment is comprised of two operating segments, Pontiki Coal, LLC’s (“Pontiki”) and MC Mining, LLC’s mining complexes.
• Northern Appalachian reportable segment is comprised of multiple operating segments, including Mettiki Coal, LLC’s mining complex (“Mettiki”), Mettiki Coal (WV), LLC’s Mountain View mining complex (“Mountain View”), two small third-party mining operations (one of which ceased operations in July 2011), a mining complex currently under construction at Tunnel Ridge, LLC (“Tunnel Ridge”) and the Penn Ridge Coal, LLC (“Penn Ridge”) property. In May 2010, incidental production began from mine development activities at Tunnel Ridge; however, longwall production is not anticipated until early in the second quarter of 2012. We are in the process of permitting the Penn Ridge property for future mine development.
• Other and Corporate reportable segment includes marketing and administrative expenses, Matrix Design Group, LLC (“Matrix Design”), Alliance Design Group, LLC (collectively, Matrix Design and Alliance Design Group, LLC are referred to as the “Matrix Group”), the Mt. Vernon Transfer Terminal, LLC (“Mt. Vernon”) dock activities, coal brokerage activity, Alliance WOR Properties, LLC, Alliance WOR Processing, LLC (“WOR Processing”), our equity investment in Mid-America Carbonates, LLC (“MAC”) and certain properties of Alliance Resource Properties. WOR Processing includes both our surface operations at White Oak Resources, LLC (“White Oak”) currently under construction and our equity investment in White Oak. For more information on White Oak, please read “Part I. Item 1. Financial Statements (Unaudited) – Note 7. White Oak Transactions” of this Quarterly Report on Form 10-Q.

Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

We reported record net income of $104.1 million for the three months ended September 30, 2011 (“2011 Quarter”) compared to $73.2 million for the three months ended September 30, 2010 (“2010 Quarter”). This increase of $30.9 million was principally due to improved pricing resulting in a record quarterly average coal sales price of $56.89 per ton sold, as compared to $51.68 per ton sold for the 2010 Quarter, and record coal sales volumes, which increased to 8.3 million tons for the 2011 Quarter compared to 7.7 million tons for the 2010 Quarter. We had higher tons produced of 7.6 million tons in the 2011 Quarter, compared to 7.1 million tons produced in the 2010 Quarter. The increase in produced tons primarily reflects increased production from our River View, Pattiki and Gibson North mines. Higher operating expenses during the 2011 Quarter resulted primarily from increased sales and production volumes, which particularly impacted materials and supplies expenses, sales-related expenses, maintenance costs and labor-related expenses. Increased operating expenses also reflect increased incidental production at our Tunnel Ridge mine development project and higher outside coal purchases.

(in thousands)

Coal sales. Coal sales for the 2011 Quarter increased 19.4% to $473.7 million from $396.7 million for the 2010 Quarter. The increase of $77.0 million in coal sales reflected the benefit of record coal sales prices (contributing $43.4 million in coal sales) and tons sold (contributing $33.6 million in additional coal sales). Average coal sales prices in the 2011 Quarter increased $5.21 per ton sold to $56.89 per ton in the 2011 Quarter compared to $51.68 per ton in the 2010 Quarter primarily as a result of improved contract pricing across all regions, particularly increased pricing of coal sold into the export market.

Operating expenses and outside coal purchases. Operating expenses and outside coal purchases increased 16.5% to $314.6 million for the 2011 Quarter from $270.1 million for the 2010 Quarter primarily due to record coal sales, increased production volumes and higher outside coal purchases. On a per ton basis, operating expenses and outside coal purchases increased 7.4% to $37.79 per ton sold. Various significant factors related to the operating and outside coal purchases expense and per ton variances are discussed below:

• Labor and benefit expenses per ton produced, excluding workers’ compensation, increased 13.3% to $12.54 per ton in the 2011 Quarter from $11.07 per ton in the 2010 Quarter. This increase of $1.47 per ton represents increased labor costs and health care costs at our Illinois Basin mines, higher mine development labor and benefits at our Tunnel Ridge mine and the impact of decreased coal recoveries at our Dotiki, Warrior and Gibson mines, partially offset by increased production at our Pattiki and Central Appalachian mines;
• Workers’ compensation expenses per ton produced decreased to $1.09 per ton in the 2011 Quarter from $1.31 per ton in the 2010 Quarter. The decrease of $0.22 per ton produced resulted primarily from unfavorable reserve adjustments for claims incurred during the 2010 Quarter;
• Material and supplies expenses per ton produced increased 11.4% to $12.33 per ton in the 2011 Quarter from $11.07 per ton in the 2010 Quarter. The increase of $1.26 per ton produced resulted from an increase in costs for certain products and services, primarily roof support (increase of $0.40 per ton), certain safety related materials and supplies (increase of $0.32 per ton), contract labor used in the mining process (increase of $0.27 per ton), power and fuel used in the mining process (increase of $0.19 per ton) and ventilation (increase of $0.14 per ton) in addition to the negative cost impact of heightened regulatory oversight;
• Maintenance expenses per ton produced increased 11.5% to $4.18 per ton in the 2011 Quarter from $3.75 per ton in the 2010 Quarter. The increase of $0.43 per ton produced was primarily due to higher maintenance costs in various equipment categories in the Illinois Basin and Northern Appalachian regions;
• Mine administration expenses increased $1.9 million for the 2011 Quarter compared to the 2010 Quarter, primarily due to increased regulatory costs across all regions, increased costs associated with Matrix Design products and research, and higher insurance costs;
• Production taxes and royalties expenses (which were incurred as a percentage of coal sales prices and volumes) increased $0.17 per produced ton sold in the 2011 Quarter compared to the 2010 Quarter primarily as a result of increased average coal sales prices across all regions;
• The operating expenses increases described above were partially offset in the 2011 Quarter by a decrease in contract mining expenses of $1.5 million for the 2011 Quarter compared to the 2010 Quarter due principally to decreased production expenses at our third-party mining operations and the closure of one third-party mining operation in the Northern Appalachian region during July 2011; and
• Outside coal purchases increased to $19.9 million for the 2011 Quarter from $5.7 million in the 2010 Quarter. The increase of $14.2 million was primarily attributable to increased coal brokerage activity as well as Mettiki’s higher cost per ton of coal purchased.

General and administrative. General and administrative expenses for the 2011 Quarter decreased to $13.3 million compared to $14.3 million in the 2010 Quarter. The decrease of $1.0 million was primarily due to decreases in expense for certain incentive compensation plans and lower contributions to industry and advocacy groups.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased to $40.3 million for the 2011 Quarter from $37.6 million for the 2010 Quarter. The increase of $2.7 million was attributable to additional depreciation expense associated with capital expenditures related to the expansion of our River View mine and capital expenditures related to various infrastructure improvements and efficiency projects at other mining operations.

Interest expense. Interest expense, net of capitalized interest, increased to $8.8 million for the 2011 Quarter from $7.6 million for the 2010 Quarter. The increase of $1.2 million was principally attributable to increased interest expense resulting from our $300 million term loan, which was completed in the fourth quarter of 2010, partially offset by reduced interest expense resulting from our August 2011 principal repayment of $18.0 million on our original senior notes issued in 1999, each of which is discussed in more detail below under “–Debt Obligations.”

Transportation revenues and expenses. Transportation revenues and expenses were $7.4 million and $7.1 million for the 2011 and 2010 Quarters, respectively. The increase of $0.3 million was primarily attributable to an increase in average transportation rates of $0.50 per ton in the 2011 Quarter compared to the 2010 Quarter reflecting in part higher fuel costs, offset by reduced tonnage in the 2011 Quarter for which we arranged tonnage compared to the 2010 Quarter. The cost of transportation services are passed through to our customers. Consequently, we do not realize any gain or loss on transportation revenues.

Income tax expense (benefit). The income tax benefit was $0.3 million for the 2011 Quarter compared to income tax expense of $1.0 million for the 2010 Quarter. Income taxes are primarily due to the operations of Matrix Design, which is owned by our subsidiary, Alliance Service, Inc. The income tax benefit was due to operating losses in the 2011 Quarter from our Matrix Design operation.

Segment Adjusted EBITDA. Our 2011 Quarter Segment Adjusted EBITDA increased $32.3 million, or 24.2%, to a record $166.0 million from the 2010 Quarter Segment Adjusted EBITDA of $133.7 million. Segment Adjusted EBITDA, tons sold, coal sales, other sales and operating revenues and Segment Adjusted EBITDA Expense by segment are (in thousands):

(1) Percentage change was greater than or equal to 100%.

(2) Segment Adjusted EBITDA (a non-GAAP financial measure) is defined as net income before net interest expense, income taxes, depreciation, depletion and amortization, and general and administrative expenses. Segment Adjusted EBITDA is a key component of consolidated EBITDA, which is used as a supplemental financial measure by 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.

Segment Adjusted EBITDA is also used as a supplemental financial measure by our management for reasons similar to those stated in the above explanation of EBITDA. In addition, the exclusion of corporate general and administrative expenses from Segment Adjusted EBITDA allows management to focus solely on the evaluation of segment operating profitability as it relates to our revenues and operating expenses, which are primarily controlled by our segments.

The following is a reconciliation of consolidated Segment Adjusted EBITDA to net income, the most comparable GAAP financial measure (in thousands):

(3) Segment Adjusted EBITDA Expense (a non-GAAP financial measure) includes operating expenses, outside coal purchases and other income. Transportation expenses are excluded as these expenses are passed through to our customers and, consequently, we do not realize any gain or loss on transportation revenues. Segment Adjusted EBITDA Expense is used as a supplemental financial measure by our management to assess the operating performance of our segments. Segment Adjusted EBITDA Expense is a key component of EBITDA in addition to coal sales and other sales and operating revenues. The exclusion of corporate general and administrative expenses from Segment Adjusted EBITDA Expense allows management to focus solely on the evaluation of segment operating performance as it primarily relates to our operating expenses. Outside coal purchases are included in Segment Adjusted EBITDA Expense because tons sold and coal sales include sales from outside coal purchases.

The following is a reconciliation of consolidated Segment Adjusted EBITDA Expense to operating expense, the most comparable GAAP financial measure (in thousands):

Illinois Basin – Segment Adjusted EBITDA increased 11.4% to $127.2 million in the 2011 Quarter from $114.2 million in the 2010 Quarter. This increase of $13.0 million was primarily attributable to increased contract pricing reflecting a higher average sales price of $50.83 per ton sold for the 2011 Quarter compared to $47.67 per ton sold for the 2010 Quarter, as well as higher tons sold which increased 5.7% to 6.6 million tons in the 2011 Quarter. Coal sales increased 12.7% to $337.0 million in the 2011 Quarter compared to $299.2 million in the 2010 Quarter. The increase of $37.8 million primarily reflects the increase in the average coal sales price discussed above and increased tons produced and sold from the expansion of production capacity at our River View mine and resumption of full production at our Pattiki mine in the first quarter of 2011, offset partially by difficult mining conditions affecting certain other mining operations. Total Segment Adjusted EBITDA Expense for the 2011 Quarter increased 13.4% to $210.0 million from $185.2 million in the 2010 Quarter and increased $2.16 per ton sold to $31.67 from $29.51 per ton sold, primarily as a result of certain cost increases described above under consolidated operating expenses. In addition, increased labor costs combined with lower production and coal recoveries at our Warrior and Dotiki mines due to difficult mining conditions increased Segment Adjusted EBITDA Expense per ton, partially offset by higher production at our River View, Gibson North and Pattiki mines.

Central Appalachia – Segment Adjusted EBITDA increased 49.9% to $12.5 million for the 2011 Quarter compared to $8.3 million in the 2010 Quarter. The increase of $4.2 million was primarily attributable to increased tons sold, which increased 16.0% to 0.6 million tons sold in the 2011 Quarter, as well as improved contract pricing resulting in a higher average coal sales price of $79.99 per ton sold during the 2011 Quarter compared to $78.18 per ton sold for the 2010 Quarter. Total Segment Adjusted EBITDA Expense for the 2011 Quarter increased 10.9% to $36.8 million from $33.2 million in the 2010 Quarter, primarily as a result of increased sales volumes and certain cost increases described above under consolidated operating expenses, particularly the impact of increasingly stringent regulatory compliance. Although Segment Adjusted EBITDA Expense increased, Segment Adjusted EBITDA expense per ton decreased 4.4% to $59.76 per ton in the 2011 Quarter from $62.52 per ton in the 2010 Quarter, primarily as a result of increased production at both Central Appalachian mines and particularly Pontiki, which added a fourth mining unit during the quarter ended June 30, 2011.

Northern Appalachia – Segment Adjusted EBITDA increased to $23.7 million for the 2011 Quarter as compared to $8.8 million in the 2010 Quarter. This increase of $14.9 million was primarily attributable to improved contract pricing in the export coal markets resulting in a higher average sales price of $89.89 per ton sold for the 2011 Quarter compared to $64.63 per ton sold for the 2010 Quarter. Total Segment Adjusted EBITDA Expense for the 2011 Quarter increased 10.0% to $50.9 million from $46.3 million in the 2010 Quarter and increased $6.82 per ton sold to $62.07 from $55.25 per ton sold, primarily as a result of increased cost per ton of coal purchased for sale, the impact of seasonal miners’ vacation and a longwall move at our Mountain View mine. Total Segment Adjusted EBITDA Expense for the 2011 Quarter was also impacted by the other cost increases described above under consolidated operating expenses, including expenses related to our Tunnel Ridge mine development project, offset in part by improved coal recoveries in the 2011 Quarter compared to the 2010 Quarter.

Other and Corporate – Segment Adjusted EBITDA increased $0.3 million in the 2011 Quarter from the 2010 Quarter. This increase was primarily attributable to higher coal brokerage sales. Other sales and operating revenues decreased 16.6% to $9.0 million in the 2011 Quarter compared to $10.8 million for the 2010 Quarter. The decrease of $1.8 million was primarily attributable to decreased sales of mine safety equipment by the Matrix Group to our other mining subsidiaries (which are eliminated upon consolidation). Segment Adjusted EBITDA Expense increased 93.7% to $20.0 million for the 2011 Quarter compared to $10.3 million for the 2010 Quarter, primarily due to higher coal brokerage expenses associated with increased brokerage coal sales as well as increased component expenses and research costs associated with services revenue and safety equipment sales by the Matrix Group.

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

We reported record net income of $297.7 million for the nine months ended September 30, 2011 (“2011 Period”) compared to $233.7 million for the nine months ended September 30, 2010 (“2010 Period”). This increase of $64.0 million was principally due to improved pricing resulting in an average coal sales price of $55.73 per ton sold for the 2011 Period, as compared to $50.86 per ton sold in the 2010 Period. We had tons sold of 23.8 million and tons produced of 23.4 million in the 2011 Period compared to 22.5 million tons sold and 21.6 million tons produced in the 2010 Period. This increase in produced tons primarily reflects increased production from our River View mine. Higher operating expenses during the 2011 Period resulted primarily from increased sales and production volumes, which particularly impacted materials and supplies expenses, sales-related expenses, maintenance costs and labor costs. Increased operating expenses also reflect increased incidental production at our Tunnel Ridge mine development project and higher outside coal purchases.

(in thousands)

Coal sales. Coal sales for the 2011 Period increased 15.4% to $1.3 billion from $1.1 billion for the 2010 Period. The increase of $177.1 million in coal sales reflected the benefit of higher average coal sales prices (contributing $115.6 million in coal sales) and increased tons sold (contributing $61.5 million in additional coal sales). Average coal sales prices increased $4.87 per ton sold to $55.73 per ton in the 2011 Period as compared to $50.86 per ton sold in the 2010 Period, primarily as a result of improved contract pricing across all regions as well as increased pricing of export market sales.

Operating expenses and outside coal purchases. Operating expenses and outside coal purchases increased 13.4% to $864.5 million for the 2011 Period from $762.5 million for the 2010 Period primarily due to increased coal sales, production volumes and outside coal purchases. On a per ton basis, operating expenses and outside coal purchases increased 7.6% to $36.39 per ton sold. Various significant factors related to the operating and outside coal purchases expense and per ton variances are discussed below:

• Labor and benefit expenses per ton produced, excluding workers’ compensation, increased 8.6% to $11.71 per ton in the 2011 Period from $10.78 per ton in the 2010 Period. This increase of $0.93 per ton represents increased labor costs at our Illinois Basin and Mettiki mines and higher mine development labor and benefits at our Tunnel Ridge mine, partially offset by increased production at our River View, Pattiki and Central Appalachian mines;
• Workers’ compensation expenses per ton produced decreased to $1.07 per ton in the 2011 Period from $1.10 per ton in the 2010 Period. The decrease of $0.03 per ton produced resulted primarily from unfavorable reserve adjustments for claims incurred during the 2010 Period;
• Material and supplies expenses per ton produced increased 15.6% to $11.93 per ton in the 2011 Period from $10.32 per ton in the 2010 Period. The increase of $1.61 per ton produced resulted from an increase in costs for certain products and services, primarily roof support (increase of $0.47 per ton), outside services and contract labor used in the mining process (increase of $0.39 per ton), power and fuel used in the mining process (increase of $0.27 per ton), certain safety related materials and supplies (increase of $0.18 per ton) and ventilation (increase of $0.14 per ton), in addition to the negative cost impact of heightened regulatory oversight;
• Maintenance expenses per ton produced increased 14.9% to $4.09 per ton in the 2011 Period from $3.56 per ton in the 2010 Period. The increase of $0.53 per ton produced was primarily due to higher maintenance costs on continuous miners in the Illinois Basin and Northern Appalachian regions, increased longwall maintenance costs at our Mettiki mine and higher costs in other various categories;
• Mine administration expenses increased $7.9 million for the 2011 Period compared to the 2010 Period, primarily due to increased regulatory costs, insurance costs and increased components expense associated with safety equipment sales by the Matrix Group. In addition, mine administration expenses increased during the 2011 Period due to costs incurred at Tunnel Ridge and Warrior related to reserve studies and mine planning activities;
• Contract mining expenses increased $0.4 million for the 2011 Period compared to the 2010 Period. The increase primarily reflects increased production expenses from our existing contract mining operations in Northern Appalachia, offset in part by the closure of one third-party mining operation during July 2011;
• Production taxes and royalties expenses (which were incurred as a percentage of coal sales prices and volumes) increased $0.32 per produced ton sold in the 2011 Period compared to the 2010 Period primarily as a result of increased average coal sales prices across all regions;
• The operating expenses increases described above were partially offset in the 2011 Period by a 1.0 million reduction in tons sold from higher cost per ton beginning of the year coal inventory compared to the 2010 Period;
• Operating expenses for the 2010 Period included $1.2 million related to the retirement of certain assets related to the failed vertical hoist conveyor system at our Pattiki mine. For more information on Pattiki, please read “Part I. Item 1. Financial Statements (Unaudited) – Note 4. Pattiki Vertical Hoist Conveyor System Failure In 2010” of this Quarterly Report on Form 10-Q; and
• Outside coal purchases increased to $29.5 million for the 2011 Period compared to $12.1 million in the 2010 Period. The increase of $17.4 million was primarily attributable to increased coal brokerage activity as well as Mettiki’s higher cost per ton of coal purchased.

General and administrative. General and administrative expenses for the 2011 Period increased to $38.7 million compared to $36.6 million in the 2010 Period. The increase of $2.1 million was primarily due to increases in salary expense and certain incentive compensation expenses, partially offset by lower contributions to certain industry and advocacy groups.

Other sales and operating revenues. Other sales and operating revenues are principally comprised of Mt. Vernon transloading revenues, Matrix Design and other outside services and administrative services revenue from affiliates. Other sales and operating revenues increased to $19.6 million for the 2011 Period from $19.1 million for the 2010 Period. The increase of $0.5 million was primarily attributable to increased freeze proofing sales.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased to $117.2 million for the 2011 Period from $109.6 million for the 2010 Period. The increase of $7.6 million was primarily attributable to additional depreciation expense associated with capital expenditures related to the expansion of our River View mine, infrastructure and equipment expenditures at our Dotiki mine and capital expenditures related to various infrastructure improvements and efficiency projects at other mining operations.

Interest expense. Interest expense, net of capitalized interest, increased to $27.2 million for the 2011 Period from $22.7 million for the 2010 Period. The increase of $4.5 million was principally attributable to increased interest expense resulting from our $300 million term loan, which was completed in the fourth quarter of 2010, partially offset by reduced interest expense from our August 2011 and 2010 principal repayments of $18.0 million on our original senior notes issued in 1999, each of which is discussed in more detail below under “–Debt Obligations.”

Income tax expense (benefit). The income tax benefit was $0.2 million for the 2011 Period compared to income tax expense of $1.6 million for the 2010 Period. Income taxes are primarily due to the operations of Matrix Design, which is owned by our subsidiary, Alliance Service, Inc. The income tax benefit was due to operating losses in the 2011 Period from our Matrix Design operation.

Segment Adjusted EBITDA. Our 2011 Period Segment Adjusted EBITDA increased $76.4 million, or 18.9%, to $480.3 million from the 2010 Period Segment Adjusted EBITDA of $403.9 million. Segment Adjusted EBITDA, tons sold, coal sales, other sales and operating revenues and Segment Adjusted EBITDA Expense by segment are (in thousands):

(1) Percentage change was greater than or equal to 100%.

(2) Segment Adjusted EBITDA (a non-GAAP financial measure) is defined as net income before net interest expense, income taxes, depreciation, depletion and amortization, and general and administrative expenses. Segment Adjusted EBITDA is a key component of consolidated EBITDA, which is used as a supplemental financial measure by 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.

Segment Adjusted EBITDA is also used as a supplemental financial measure by our management for reasons similar to those stated in the above explanation of EBITDA. In addition, the exclusion of corporate general and administrative expenses from Segment Adjusted EBITDA allows management to focus solely on the evaluation of segment operating profitability as it relates to our revenues and operating expenses which are primarily controlled by our segments.

The following is a reconciliation of consolidated Segment Adjusted EBITDA to net income, the most comparable GAAP financial measure (in thousands):

(3) Segment Adjusted EBITDA Expense (a non-GAAP financial measure) includes operating expenses, outside coal purchases and other income. Transportation expenses are excluded as these expenses are passed through to our customers, and, consequently, we do not realize any gain or loss on transportation revenues. Segment Adjusted EBITDA Expense is used as a supplemental financial measure by our management to assess the operating performance of our segments. Segment Adjusted EBITDA Expense is a key component of EBITDA in addition to coal sales and other sales and operating revenues. The exclusion of corporate general and administrative expenses from Segment Adjusted EBITDA Expense allows management to focus solely on the evaluation of segment operating performance as it primarily relates to our operating expenses. Outside coal purchases are included in Segment Adjusted EBITDA Expense because tons sold and coal sales include sales from outside coal purchases.

The following is a reconciliation of consolidated Segment Adjusted EBITDA Expense to operating expense, the most comparable GAAP financial measure (in thousands):

Illinois Basin – Segment Adjusted EBITDA increased 11.0% to $382.1 million for the 2011 Period from $344.2 million for the 2010 Period. This increase of $37.9 million was primarily attributable to increased contract pricing reflecting a higher average sales price of $50.39 per ton sold for the 2011 Period compared to $47.43 per ton sold for the 2010 Period, as well as higher tons sold which increased 3.6% to 19.1 million tons in the 2011 Period. Coal sales increased 10.1% to $964.1 million in the 2011 Period compared to $875.8 million in the 2010 Period. The increase of $88.3 million primarily reflects the increase in average coal sales price discussed above and increased tons produced and sold from expansion of production capacity at our River View mine and resumption of full production at our Pattiki mine in the first quarter of 2011, offset partially by weather disruptions and difficult mining conditions affecting certain mining operations. Total Segment Adjusted EBITDA Expense for the 2011 Period increased 9.5% to $583.3 million from $532.6 million in the 2010 Period and increased $1.65 per ton sold to $30.49 from $28.84 per ton sold, primarily as a result of certain cost increases described above under consolidated operating expenses, as well as lower production at the Dotiki and Warrior mines due to difficult mining conditions and weather related disruptions at the Gibson North and Hopkins mines. These increases were partially offset by higher production at our River View and Pattiki mines in the 2011 Period and the impact on the 2010 Period of a $1.2 million loss on the retirement of certain assets related to the failed vertical hoist conveyor system at our Pattiki mine. For more information on Pattiki, please read “Part I. Item 1. Financial Statements (Unaudited) – Note 4. Pattiki Vertical Hoist Conveyor System Failure In 2010” of this Quarterly Report on Form 10-Q.

Central Appalachia – Segment Adjusted EBITDA increased 80.6% to $43.6 million for the 2011 Period, compared to $24.1 million for the 2010 Period. The increase of $19.5 million was primarily attributable to increased tons sold, which increased 14.2% to 1.9 million tons sold in the 2011 Period, as well as improved contract pricing resulting in a higher average coal sales price of $79.93 per ton sold during the 2011 Period compared to $72.59 per ton sold for the 2010 Period. Total Segment Adjusted EBITDA Expense for the 2011 Period increased 12.2% to $109.8 million from $97.9 million in the 2010 Period, primarily as a result of certain cost increases described above under consolidated operating expenses, particularly the impact of increasingly stringent regulatory compliance. Although Segment Adjusted EBITDA Expense increased, Segment Adjusted EBITDA expense per ton decreased 1.8% to $57.26 per ton in the 2011 Period from $58.29 per ton in the 2010 Period primarily as a result of increased production at both Central Appalachian mines and particularly Pontiki, which added a fourth mining unit during the 2011 Period.

Northern Appalachia – Segment Adjusted EBITDA increased to $49.6 million for the 2011 Period, compared to $29.9 million for the 2010 Period. The increase of $19.7 million was primarily attributable to improved contract pricing in the export coal markets resulting in a higher average sales price of $78.86 per ton sold for the 2011 Period compared to $62.11 per ton sold for the 2010 Period.

Total Segment Adjusted EBITDA Expense for the 2011 Period increased 20.0% to $143.8 million from $119.9 million in the 2010 Period and increased $8.81 on a per ton sold basis to $59.43 from $50.62 per ton sold, primarily as a result of higher coal sales volumes, increased costs associated with coal purchased for sale, and lower coal recoveries due to adverse geologic conditions, as well as the other cost increases described above under consolidated operating expenses, including expenses related to our Tunnel Ridge mine development project.

Other and Corporate – Segment Adjusted EBITDA and other sales and operating revenues decreased $0.7 million and $4.5 million, respectively, in the 2011 Period compared to the 2010 Period. These decreases were primarily attributable to lower Matrix Group safety equipment sales. Segment Adjusted EBITDA Expense increased 35.3% to $38.4 million for the 2011 Period compared to $28.3 million for the 2010 Period, primarily due to increased component expenses and research costs associated with services revenue and safety equipment sales by the Matrix Group, partially offset by an increase in equity income from MAC during the 2011 Period and a loss associated with United Kingdom currency held during the 2010 Period.

Liquidity and Capital Resources

Liquidity

We have historically satisfied our working capital requirements and funded our capital expenditures and debt service obligations from cash generated from operations, cash provided by the issuance of debt or equity and borrowings under revolving credit facilities. We believe that current cash on hand, cash generated from operations, cash from borrowings under our current credit facility and cash provided from the issuance of debt or equity will be sufficient to meet our working capital requirements, anticipated capital expenditures, scheduled debt payments, commitments and distribution payments. Our ability to satisfy our obligations, commitments and planned expenditures will depend upon our future operating performance and access to and cost of financing sources, which will be affected by prevailing economic conditions generally and in the coal industry specifically, which are beyond our control. Based on our recent operating results, current cash position, anticipated future cash flows and sources of financing that we expect to have available, we do not anticipate any significant liquidity constraints in the foreseeable future. However, to the extent operating cash flow or access to and cost of financing sources are materially different than expected, future liquidity may be adversely affected. Please read “Item 1A. Risk Factors” in the Annual Report on Form 10-K for the year ended December 31, 2010.

On September 22, 2011 (the “Transaction Date”), we entered into a series of transactions with White Oak Resources LLC (“White Oak”) and related entities to support development of a longwall mining operation currently under construction. Our initial investment on the Transaction Date was $69.5 million and we expect to fund approximately $400.0 million to $525.0 million, including initial funding, over the next three to four years. We plan to utilize current cash balances, availability under our revolving credit facility and future cash flows from existing operations to fund our commitments to the White Oak project. For more information on the White Oak transactions, please read “Part I. Item 1. Financial Statements (Unaudited) – Note 7. White Oak Transactions” of this Quarterly Report on Form 10-Q.

Cash Flows

Cash provided by operating activities was $432.3 million for the 2011 Period compared to $394.2 million for the 2010 Period. The increase in cash provided by operating activities was principally attributable to higher net income, an increase in the change in accounts payable in the 2011 Period compared to the 2010 Period and a decrease in the change in accounts receivable in the 2011 Period compared to the 2010 Period. These increases in cash provided by operating activities were partially offset by an increase in coal inventory during the 2011 Period as compared to a significant decrease during the 2010 Period.

Net cash used in investing activities was $284.1 million for the 2011 Period compared to $238.1 million for the 2010 Period. The increase in cash used for investing activities was primarily attributable to our funding of investments related to the White Oak transactions during the 2011 Period, partially offset by decreases in capital expenditures at Tunnel Ridge as a result of our construction timetable and River View due to the addition of mining units during the 2010 Period and timing differences in accounts payable and accrued liabilities compared to the 2010 Period.

Net cash used in financing activities was $180.7 million for the 2011 Period compared to $157.1 million for the 2010 Period. The increase in cash used in financing activities was primarily attributable to increased distributions paid to partners in the 2011 Period.

Capital Expenditures

Capital expenditures decreased to $216.3 million in the 2011 Period from $233.8 million in the 2010 Period. See “—Cash Flows” above for additional information regarding capital expenditures.

Our anticipated total capital expenditures for the year ending December 31, 2011 are estimated in a range of $420.0 to $475.0 million, which also includes the acquisition of coal reserves from White Oak. Management anticipates funding remaining 2011 capital requirements with cash and cash equivalents ($307.2 million as of September 30, 2011), cash flows provided by operations and borrowing available under the ARLP Credit Facility, as discussed below. We will continue to have significant capital requirements over the long-term, which may require us to obtain additional debt or equity capital. The availability and cost of additional capital will depend upon prevailing market conditions, the market price of our common units and several other factors over which we have limited control, as well as our financial condition and results of operations.

Debt Obligations

ARLP Credit Facility. Our Intermediate Partnership maintains the ARLP Credit Facility, a $142.5 million revolving credit facility that matures September 25, 2012. The ARLP Credit Facility limits our annual capital expenditures, excluding acquisitions. The capital expenditure limit is $531.9 million for 2011 and $250.0 million for 2012. The amount of any annual limit in excess of actual capital expenditures for that year carries forward and is added to the annual limit for the subsequent year.

At September 30, 2011, we had $11.6 million of letters of credit outstanding with $130.9 million available for borrowing under the ARLP Credit Facility. We had no borrowings outstanding under the ARLP Credit Facility as of September 30, 2011 or December 31, 2010. We utilize the ARLP Credit Facility, as appropriate, to meet working capital requirements, anticipated capital expenditures, scheduled debt payments or distribution payments. We incur an annual commitment fee of 0.375% on the undrawn portion of the ARLP Credit Facility.

Senior Notes. Our Intermediate Partnership has $54.0 million principal amount of 8.31% senior notes due August 20, 2014, payable in three remaining equal annual installments of $18.0 million with interest payable semi-annually (“Senior Notes”).

Series A Senior Notes. On June 26, 2008, our Intermediate Partnership entered into a Note Purchase Agreement (the “2008 Note Purchase Agreement”) with a group of institutional investors in a private placement offering. We issued $205.0 million of Series A senior notes, which bear interest at 6.28% and mature on June 26, 2015 with interest payable semi-annually.

Series B Senior Notes. On June 26, 2008, we issued under the 2008 Note Purchase Agreement $145.0 million of Series B senior notes (together with the Series A senior notes, the “2008 Senior Notes”), which bear interest at 6.72% and mature on June 26, 2018 with interest payable semi-annually.

Term Loan. On December 29, 2010, our Intermediate Partnership entered into a term loan agreement (the “Term Loan Agreement”) with various financial institutions for a term loan (the “Term Loan”) in the aggregate principal amount of $300 million. The Term Loan bears interest at a variable rate plus an applicable margin which fluctuates depending upon whether we elect the Term Loan (or a portion thereof) to bear interest at the Base Rate or the Eurodollar Rate (as defined in the Term Loan Agreement). We have elected the Eurodollar Rate which, with applicable margin, was 2.25% as of September 30, 2011. Interest is payable quarterly with principal due as follows: $15 million due per quarter beginning March 31, 2013 through December 31, 2013, $18.75 million due per quarter beginning March 31, 2014 through September 30, 2015 and the balance of $108.75 million due on December 31, 2015. We have the option to prepay the Term Loan at any time in whole or in part subject to terms and conditions described in the Term Loan Agreement. Upon a “change of control” (as defined in the Term Loan Agreement), the unpaid principal amount of the Term Loan, all interest thereon and all other amounts payable under the Term Loan Agreement will become due and payable.

We incurred debt issuance costs of approximately $1.4 million in 2010 associated with the Term Loan Agreement, which have been deferred and are being amortized as a component of interest expense over the duration of the Term Loan.

The ARLP Credit Facility, Senior Notes, 2008 Senior Notes and the Term Loan (collectively, “ARLP Debt Arrangements”) are guaranteed by all of the direct and indirect subsidiaries of our Intermediate Partnership. The ARLP Debt Arrangements contain various covenants affecting our Intermediate Partnership and its subsidiaries restricting, among other things, the amount of distributions by our Intermediate Partnership, the incurrence of additional indebtedness and liens, the sale of assets, the making of investments, the entry into mergers and consolidations and the entry into transactions with affiliates, in each case subject to various exceptions. The ARLP Debt Arrangements also require the Intermediate Partnership to remain in control of a certain amount of mineable coal reserves relative to its annual production. In addition, the ARLP Debt Arrangements require our Intermediate Partnership to maintain the following: (a) debt to cash flow ratio of not more than 3.0 to 1.0 and (b) cash flow to interest expense ratio of not less than 4.0 to 1.0, in both cases, during the four most recently ended fiscal quarters. The ARLP Credit Facility, Senior Notes and the 2008 Senior Notes limit our Intermediate Partnership’s maximum annual capital expenditures, excluding acquisitions, as described above. The debt to cash flow ratio and cash flow to interest expense ratio were 1.23 to 1.0 and 16.5 to 1.0, respectively, for the trailing twelve months ended September 30, 2011. Actual capital expenditures were $216.3 million for the 2011 Period. We were in compliance with the covenants of the ARLP Debt Arrangements as of September 30, 2011.

Other. In addition to the letters of credit available under the ARLP Credit Facility discussed above, we also have agreements with two banks to provide additional letters of credit in an aggregate amount of $31.1 million to maintain surety bonds to secure certain asset retirement obligations and our obligations for workers’ compensation benefits. At September 30, 2011, we had $30.7 million in letters of credit outstanding under agreements with these two banks. SGP previously guaranteed $5.0 million of these outstanding letters of credit. On May 4, 2011, the ARLP Partnership entered into the Amendment and Restatement of Letter of Credit Facility Agreement, dated as of October 2, 2010, which released SGP from its guarantee of these outstanding letters of credit.

Related-Party Transactions

We have continuing related-party transactions with our managing general partner, AHGP and SGP and its affiliates. These related-party transactions relate principally to the provision of administrative services to AHGP and Alliance Resource Holdings II, Inc. and their respective affiliates, a time sharing agreement concerning use of aircraft and mineral and equipment leases with SGP and its affiliates. On October 27, 2011 the MGP board of directors and conflicts committee approved our purchase from SGP Land, LLC of two aircraft, which we expect to complete prior to the end of 2011. We also had guarantees from SGP for certain letters of credit. However, these guarantees were released on May 4, 2011.

On the Transaction Date, we entered into a series of transactions with White Oak and related entities to support development of a longwall mining operation currently under construction. The transactions feature several components, including an equity investment containing certain distribution and liquidation preferences, the acquisition and leaseback of certain reserves and surface rights, a coal handling and services agreement and a backstop equipment financing facility. For more information on the White Oak transactions, please read “Part I. Item 1. Financial Statements (Unaudited) – Note 7. White Oak Transactions” of this Quarterly Report on Form 10-Q.

Please read our Annual Report on Form 10-K for the year ended December 31, 2010, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Related-Party Transactions” for additional information concerning related-party transactions.

New Accounting Standards

New Accounting Standards Issued and Adopted

In December 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2010-29, *Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations (“*ASU 2010-29”). ASU 2010-29 amended FASB’s Accounting Standards Codification (“ASC”) 805, Business Combinations, to specify that if a public entity presents comparative financial statements and a business combination has occurred during the current reporting period, then the public entity should disclose revenues and earnings of the combined entity as though the business combination that occurred during the current year had occurred at the beginning of the comparable prior annual reporting period only. The amendments also expand the supplemental pro forma disclosures under FASB ASC 805 to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenues and earnings. The adoption of the ASU 2010-29 amendments were effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. The adoption of ASU 2010-29 did not have an impact on our condensed consolidated financial statements.

New Accounting Standards Issued and Not Yet Adopted

In June 2011, the FASB issued ASU 2011-05, *Presentation of Comprehensive Income (“*ASU 2011-05”). ASU 2011-05 removes the presentation options in Accounting Standards Codification 220, Comprehensive Income, and requires entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. Under the two statement approach, the first statement would include components of net income, and the second statement would include components of other comprehensive income (“OCI”). ASU 2011-05 does not change the items that must be reported in OCI. ASU 2011-05 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, and its provisions must be applied retrospectively for all periods presented in the financial statements. We do not anticipate the adoption of ASU 2011-05 on January 1, 2012 will have a material impact on our consolidated financial statements.

Other

Health Care Reform

On March 23, 2010, President Obama signed into law the Patient Protection and Affordable Care Act (“PPACA”). Additionally, on March 30, 2010, President Obama signed into law a reconciliation measure, the Health Care and Education Reconciliation Act of 2010. Implementation of the PPACA and the Health Care and Education Reconciliation Act (collectively, the “Health Care Act”) will result in comprehensive changes to health care in the U.S. Implementation of this legislation is planned to occur in phases, with standard plan changes taking effect beginning in 2010, but to a greater extent with the 2011 benefit plan year and extending through 2018.

The Health Care Act continues to have implications on benefit plan eligibility, coverage requirements and benefit standards and limitations. In the long term, our plan’s health care costs are expected to increase for various reasons due to the Health Care Act, including the potential impact of an excise tax on “high cost” plans (beginning in 2018), among other standard requirements. We anticipate that certain government agencies will provide additional regulations or interpretations concerning the application of the Health Care Act and reporting required thereunder. Until these regulations or interpretations are published, we are unable to reasonably estimate the further impact of such federal mandate requirements on our future health care costs.

The Health Care Act amended previous legislation related to coal workers’ pneumoconiosis, or black lung, providing automatic extension of awarded lifetime benefits to surviving spouses and providing changes to the legal criteria used to assess and award claims. The impact of these changes to our current population of beneficiaries and claimants resulted in an estimated $8.3 million increase to our black lung obligation at December 31, 2010. This increase to our obligation excludes the impact of potential re-filing of closed claims and potential filing rates for employees who terminated more than seven years ago as we do not have sufficient information to determine what, if any, claims will be filed until regulations are issued. The issuance of these regulations is currently uncertain and may take place over the next several years.

We will continue to evaluate the potential impact of the Health Care Act on our self-insured long term disability plan, black lung liabilities, results of operations and internal controls as governmental agencies issue interpretations regarding the meaning and scope of the Health Care Act. However, we believe it is likely that our costs will continue to increase as a result of these provisions, which may have an adverse impact on our results of operations and cash flows.

The Dodd–Frank Act

On July 21, 2010, President Obama signed into law the Dodd—Frank Wall Street Reform and Consumer Protection Act (“Dodd—Frank Act”). The additional regulations imposed by the Dodd—Frank Act on financial institutions may result in increased costs associated with future borrowings and decreased availability of credit. However, we are presently unable to determine the significance of any potential increase in our borrowing costs or potential liquidity constraints, if any. The Dodd—Frank Act also requires public mining companies to report certain safety information regarding citations, penalties and pending legal actions in each periodic report filed with the U.S. Securities and Exchange Commission (“SEC”) and to file current reports on Form 8-K for certain safety matters. We are continuing to evaluate the effect of the Dodd—Frank Act on our operations.

Pattiki Vertical Hoist Conveyor System Failure In 2010

On May 13, 2010, White County Coal’s Pattiki mine was temporarily idled following the failure of the vertical hoist conveyor system used in conveying raw coal out of the mine. Our operating expenses for the nine months ended September 30, 2010 include $1.2 million for retirement of certain assets related to the failed vertical hoist conveyor system in addition to other repair and clean-up expenses that were not significant on a consolidated or segment basis. As the loss on the vertical hoist conveyor system did not exceed the deductible under our commercial property (including business interruption) insurance policies, we did not recover any amounts under such policies.

While the Pattiki mine was temporarily idled, we expanded coal production at our other coal mines in the region, including the addition of the seventh and eighth production units at the River View mine, to partially offset the loss of production from the Pattiki mine. Consequently, the temporary idling of the Pattiki mine did not have a material adverse impact on our results of operations and cash flows. On July 19, 2010, the Pattiki mine resumed limited production while White County Coal continued to assess the effectiveness and reliability of the repaired vertical hoist conveyor system. On January 3, 2011, the Pattiki mine returned to full production.

Insurance

During September 2011, we completed our annual property and casualty insurance renewal with various insurance coverages effective October 1, 2011. The aggregate maximum limit in the commercial property program is $100.0 million per occurrence excluding a $1.5 million deductible for property damage, a 90-day waiting period for underground business interruption and a $10.0 million overall aggregate deductible. We can make no assurances that we will not experience significant insurance claims in the future that could have a material adverse effect on our business, financial condition, results of operations and ability to purchase property insurance in the future.

Commodity Price 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 resulting from regulatory changes.

We have exposure to price risk for supplies that are used directly or indirectly in the normal course of coal production such as diesel fuel, steel, explosives and other supplies. We manage our risk for these items through strategic sourcing contracts for normal quantities required by our operations. We do not utilize any commodity price-hedges or other derivatives related to these risks.

Credit Risk

Most of our sales tonnage is consumed by electric utilities. Therefore, our credit risk is primarily with domestic electric power generators. Our policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to constantly monitor outstanding accounts receivable against established credit limits. When deemed appropriate by our credit management department, we will take steps to reduce our credit exposure to customers that do not meet our credit standards or whose credit has deteriorated. These steps may include obtaining letters of credit or cash collateral, requiring prepayments for shipments or establishing customer trust accounts held for our benefit in the event of a failure to pay.

Exchange Rate Risk

Almost 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.

Interest Rate Risk

Borrowings under the ARLP Credit Facility and Term Loan Agreement are at variable rates and, as a result, we have interest rate exposure. Historically, our earnings have not been materially affected by changes in interest rates. We do not utilize any interest rate derivative instruments related to our outstanding debt. We had no borrowings under the ARLP Credit Facility and $300.0 million outstanding under the Term Loan Agreement at September 30, 2011. A one percentage point increase in the interest rates related to the Term Loan Agreement would result in an annualized increase in 2011 interest expense of $3.0 million, based on borrowing levels at September 30, 2011. With respect to our fixed-rate borrowings, a one percentage point increase in interest rates would result in a decrease of approximately $17.6 million in the estimated fair value of these borrowings.

As of September 30, 2011, the estimated fair value of the ARLP Debt Arrangements was approximately $741.5 million. 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 September 30, 2011. There were no other changes in our quantitative and qualitative disclosures about market risk as set forth in our Annual Report on Form 10-K for the year ended December 31, 2010.

We maintain controls and procedures designed to provide reasonable assurance that information required to be disclosed in the reports we file with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure. As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Securities Exchange Act) as of September 30, 2011. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these controls and procedures are effective as of September 30, 2011.

During the quarterly period ended September 30, 2011, there have not been any changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) identified in connection with this evaluation that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

FORWARD-LOOKING STATEMENTS

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.” These statements are based on our beliefs as well as assumptions made by, and information currently available to, us. When used in this document, the words “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “may,” “project,” “will,” and similar expressions identify forward-looking statements. Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings and sources of funding are forward-looking statements. These statements reflect our current views with respect to future events and are subject to numerous assumptions that we believe are reasonable, but are open to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements. Among the factors that could cause actual results to differ from those in the forward-looking statements are:

• changes in competition in coal markets and our ability to respond to such changes;
• changes in coal prices, which could affect our operating results and cash flows;
• risks associated with the expansion of our operations and properties;
• the impact of recent health care legislation;
• deregulation of the electric utility industry or the effects of any adverse change in the coal industry, electric utility industry, or general economic conditions;
• dependence on significant customer contracts, including renewing customer contracts upon expiration of existing contracts;
• changing global economic conditions or in industries in which our customers operate;
• liquidity constraints, including those resulting from any future unavailability of financing;
• customer bankruptcies, cancellations or breaches to existing contracts, or other failures to perform;
• customer delays, failure to take coal under contracts or defaults in making payments;
• adjustments made in price, volume or terms to existing coal supply agreements;
• fluctuations in coal demand, prices and availability due to labor and transportation costs and disruptions, equipment availability, governmental regulations, including those related to carbon dioxide emissions, and other factors;
• legislation, regulatory and court decisions and interpretations thereof, including issues related to climate change and miner health and safety;
• our productivity levels and margins earned on our coal sales;
• unexpected changes in raw material costs;
• unexpected changes in the availability of skilled labor;
• our ability to maintain satisfactory relations with our employees;
• any unanticipated increases in labor costs, adverse changes in work rules, or unexpected cash payments or projections 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;
• risks associated with major mine-related accidents, such as mine fires, or interruptions;
• results of litigation, including claims not yet asserted;
• difficulty maintaining our surety bonds for mine reclamation as well as workers’ compensation and black lung benefits;
• difficulty in making accurate assumptions and projections regarding pension, black lung benefits and other post-retirement benefit liabilities;
• coal market’s share of electricity generation, including as a result of environmental concerns related to coal mining and combustion and the cost and perceived benefits of alternative sources of energy, such as natural gas, nuclear energy and renewable fuels;
• uncertainties in estimating and replacing our coal reserves;
• a loss or reduction of benefits from certain tax credits;
• difficulty obtaining commercial property insurance, and risks associated with our participation (excluding any applicable deductible) in the commercial insurance property program; and
• other factors, including those discussed in “Part II. Item 1A. Risk Factors” and “Part II. Item 1. Legal Proceedings” of this Quarterly Report on Form 10-Q.

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 risks described in “Risk Factors” below. These risks 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 or considering any forward-looking statements contained in:

• this Quarterly Report on Form 10-Q;
• other reports filed by us with the SEC;
• our press releases;
• our website http://www.arlp.com; and
• written or oral statements made by us or any of our officers or other authorized persons acting on our behalf.

PART II

OTHER INFORMATION

In addition to the other information set forth in this Quarterly Report on Form 10-Q, you should carefully consider the factors discussed in Part I, Item 1A “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2010 which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K and this Quarterly Report on Form 10-Q are not our only risks. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial based on current knowledge and factual circumstances, if such knowledge or facts change, also may materially adversely affect our business, financial condition and/or operating results in the future.