Royal Energy Resources, Inc. - FORM 8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): February 1, 2016

ROYAL ENERGY RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Delaware		000-52547		11-3480036
(State or other jurisdiction of incorporation)		(Commission file number)		(I.R.S. Employer Identification Number)

56 Broad Street, Suite 2, Charleston, SC 29401

(Address of principal executive offices) (Zip Code)

(843) 900-7693

(Registrant’s telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

[ ] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

[ ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

[ ] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

[ ] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4c))

Section 3 – Securities and Trading Markets

Item 3.02 Unregistered Sales of Equity Securities.

On February 1, 2016, Royal Energy Resources, Inc. (the “Company”) commenced a private offering of its common stock under SEC Rule 506, under which the Company is offering up to 2,187,500 shares of common stock at a price of $8.00 per share, for maximum gross proceeds of $17,500,000. The Company expects to use the proceeds to increase its investment in Rhino Resource Partners, LP, to fund the acquisition of other natural resource assets, and for general working capital purposes.

SIGNATURES

In accordance with the requirements of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	ROYAL ENERGY RESOURCES, INC.

Date: February 5, 2016	By:	/s/ William L. Tuorto
		William L. Tuorto, Chief Executive Officer

EXHIBIT A

Description of Business of Rhino Resource Partners, LP

The following description of Rhino’s business and assets derived from Rhino’s Annual Report on Form 10-K for the year ended December 31, 2014, as filed with the Securities and Exchange Commission on March 11, 2015, and its subsequent Form 10-Q’s and 8-K’s. The discussion has been modified to delete references to certain assets that were disposed of after the Form 10-K was filed.

For a more complete description of Rhino’s business, financial statements, management, executive compensation, related party transactions, and other factors, investors should review Rhino’s reports filed with the SEC available at www.sec.gov, including:

Report		File Date

Form 10-K for the year ended December 31, 2014		March 11, 2015

Form 10-Q for the three months ended March 31, 2015		May 6, 2015

Form 10-Q for the six months ended June 30, 2015		August 7, 2015

Form 10-Q for the nine months ended September 30, 2015		November 6, 2015

GLOSSARY OF KEY TERMS

ash: Inorganic material consisting of iron, alumina, sodium and other incombustible matter that are contained in coal. The composition of the ash can affect the burning characteristics of coal.

assigned reserves: Proven and probable reserves that have the permits and infrastructure necessary for mining.

as received: Represents an analysis of a sample as received at a laboratory.

Btu: British thermal unit, or Btu, is the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit.

Central Appalachia: Coal producing area in eastern Kentucky, Virginia and southern West Virginia.

coal seam: Coal deposits occur in layers typically separated by layers of rock. Each layer is called a “seam.” A seam can vary in thickness from inches to a hundred feet or more.

coke: A hard, dry carbon substance produced by heating coal to a very high temperature in the absence of air. Coke is used in the manufacture of iron and steel.

fossil fuel: A hydrocarbon such as coal, petroleum or natural gas that may be used as a fuel.

GAAP: Generally accepted accounting principles in the United States.

high-vol metallurgical coal: Metallurgical coal that has a volatility content of 32% or greater of its total weight.

Illinois Basin: Coal producing area in Illinois, Indiana and western Kentucky.

limestone: A rock predominantly composed of the mineral calcite (calcium carbonate (CaCO₃)).

lignite: The lowest rank of coal. It is brownish-black with high moisture content commonly above 35% by weight and heating value commonly less than 8,000 Btu.

low-vol metallurgical coal: Metallurgical coal that has a volatility content of 17% to 22% of its total weight.

mid-vol metallurgical coal: Metallurgical coal that has a volatility content of 23% to 31% of its total weight.

Metallurgical, or “met”, coal: The various grades of coal suitable for carbonization to make coke for steel manufacture. Its quality depends on four important criteria: volatility, which affects coke yield; the level of impurities including sulfur and ash, which affects coke quality; composition, which affects coke strength; and basic characteristics, which affect coke oven safety. Metallurgical coal typically has a particularly high Btu but low ash and sulfur content.

net mineral acre: The product of (i) the percentage of oil and natural gas mineral rights owned in a given tract of land and (ii) the total surface acreage of such tract.

non-reserve coal deposits: Non-reserve coal deposits are coal-bearing bodies that have been sufficiently sampled and analyzed in trenches, outcrops, drilling and underground workings to assume continuity between sample points, and therefore warrant further exploration stage work. However, this coal does not qualify as a commercially viable coal reserve as prescribed by standards of the SEC until a final comprehensive evaluation based on unit cost per ton, recoverability and other material factors concludes legal and economic feasibility. Non-reserve coal deposits may be classified as such by either limited property control or geologic limitations, or both.

Northern Appalachia: Coal producing area in Maryland, Ohio, Pennsylvania and northern West Virginia.

overburden: Layers of earth and rock covering a coal seam. In surface mining operations, overburden is removed prior to coal extraction.

preparation plant: Usually located on a mine site, although one plant may serve several mines. A preparation plant is a facility for crushing, sizing and washing coal to prepare it for use by a particular customer. The washing process separates higher ash coal and may also remove some of the coal’s sulfur content.

probable (indicated) coal reserves: Coal reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.

proven (measured) coal reserves: Coal reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

reclamation: The process of restoring land to its prior condition, productive use or other permitted condition following mining activities. The process commonly includes “re-contouring” or reshaping the land to its approximate original contour, restoring topsoil and planting native grass and shrubs. Reclamation operations are typically conducted concurrently with mining operations, but the majority of reclamation costs are incurred once mining operations cease. Reclamation is closely regulated by both state and federal laws.

recompletion: The process of re-entering an existing wellbore that is either producing or not producing and completing new oil and natural gas reservoirs in an attempt to establish or increase existing production.

reserve: That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.

steam coal: Coal used by power plants and industrial steam boilers to produce electricity, steam or both. It generally is lower in Btu heat content and higher in volatile matter than metallurgical coal.

sulfur: One of the elements present in varying quantities in coal that contributes to environmental degradation when coal is burned. Sulfur dioxide (SO2) is produced as a gaseous by-product of coal combustion.

surface mine: A mine in which the coal lies near the surface and can be extracted by removing the covering layer of soil overburden. Surface mines are also known as open-pit mines.

tons: A “short” or net ton is equal to 2,000 pounds. A “long” or British ton is 2,240 pounds. A “metric” tonne is approximately 2,205 pounds. The short ton is the unit of measure referred to in this report.

Western Bituminous region: Coal producing area located in western Colorado and eastern Utah.

We are a diversified energy limited partnership formed in Delaware that is focused on coal and energy related assets and activities, including energy infrastructure investments. We produce, process and sell high quality coal of various steam and metallurgical grades from multiple coal producing basins in the United States. We market our steam coal primarily to electric utility companies as fuel for their steam powered generators. Customers for our metallurgical coal are primarily steel and coke producers who use our coal to produce coke, which is used as a raw material in the steel manufacturing process. In addition to operating coal properties, we manage and lease coal properties and collect royalties from such management and leasing activities. In addition, we have expanded our business to include infrastructure support services, including the formation of a service company to provide drill pad construction for operators in the Utica Shale as well as other joint venture investments to provide for the transportation of hydrocarbons and drilling support services in the Utica Shale region. We have also invested in joint ventures that will provide sand for fracking operations to drillers in the Utica Shale region and other oil and natural gas basins in the United States.

We have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region. As of December 31, 2014, we controlled an estimated 480.0 million tons of proven and probable coal reserves, consisting of an estimated 425.1 million tons of steam coal and an estimated 54.9 million tons of metallurgical coal. In addition, as of December 31, 2014, we controlled an estimated 290.0 million tons of non-reserve coal deposits. As discussed further below, Rhino Eastern LLC, a joint venture in which we had a 51% membership interest and for which we served as manager, was dissolved in January 2015. As part of this dissolution, we received approximately 34 million tons of premium metallurgical coal reserves, which we have included in the proven and probable reserves listed above since the joint venture and its operations were effectively dissolved as of December 31, 2014.

As of December 31, 2014, we operated nine mines, including four underground and five surface mines, located in Kentucky, Ohio, West Virginia and Utah. The number of mines that we operate will vary from time to time depending on a number of factors, including the existing demand for and price of coal, depletion of economically recoverable reserves and availability of experienced labor.

Due to the prolonged weakness in the U.S. coal markets and the dim prospects for an upturn in the coal markets in the near term, in the fourth quarter of 2014, we performed a comprehensive review of our current coal mining operations as well as potential future development projects to ascertain whether any of our investments were no longer recoverable. We identified various properties, projects and operations that were potentially impaired based upon changes in our strategic plans, market conditions or other factors. We recorded approximately $45.3 million of asset impairment and related charges for the year ended December 31, 2014. We also recorded an additional $5.9 million impairment charge as of December 31, 2014 related to the January 2015 dissolution of our Rhino Eastern joint venture that is discussed further below. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”, for a detailed discussion of these asset impairment and related charges.

In January 2015, we completed a Membership Transfer Agreement (the “Transfer Agreement”) with an affiliate of Patriot Coal Corporation (“Patriot”) that terminated the Rhino Eastern joint venture. Pursuant to the Transfer Agreement, Patriot sold and assigned its 49% membership interest in the Rhino Eastern joint venture to us and, in consideration of this transfer, Patriot received certain fixed assets, leased equipment and coal reserves associated with the mining area previously operated by the Rhino Eastern joint venture. Patriot also assumed substantially all of the active workforce related to the Eagle mining area that was previously employed by the Rhino Eastern joint venture. We retained approximately 34 million tons of coal reserves that are not related to the Eagle mining area as well as a prepaid advanced royalty balance of $6.3 million. As part of the closing of the Transfer Agreement, we and Patriot agreed to a dissolution payment based upon a final working capital adjustment calculation as defined in the Transfer Agreement.

Excluding results from the Rhino Eastern joint venture, for the year ended December 31, 2014, we produced approximately 3.4 million tons of coal, purchased approximately 0.1 million tons of coal and sold approximately 3.6 million tons of coal. Additionally, the Rhino Eastern joint venture produced and sold approximately 0.2 million tons of premium mid-vol metallurgical coal for the year ended December 31, 2014. Lessees produced approximately 2.9 million tons of coal from our Elk Horn coal leasing properties in eastern Kentucky for the year ended December 31, 2014. Please see Note 21 of the consolidated financial statements included elsewhere in this annual report for information regarding our reportable business segments.

Our principal business strategy is to safely, efficiently and profitably produce, sell and lease both steam and metallurgical coal from our diverse asset base in order to maintain, and, over time, increase our quarterly cash distributions. In addition, we intend to potentially diversify our operations through strategic acquisitions, including the acquisition of long-term, cash generating natural resource assets. We believe that such assets will enhance the stability of our cash flow.

History

Our predecessor was formed in April 2003 by Wexford Capital LP (“Wexford Capital”, and together with certain of its affiliates and principals, “Wexford”). Wexford Capital is an SEC registered investment advisor which was formed in 1994 and manages a series of investment funds and has approximately $3.5 billion of assets under management. Since the formation of our predecessor, we have significantly grown our coal reserves. Since April 2003, we have completed numerous coal asset acquisitions with a total purchase price of approximately $357.5 million. Through these acquisitions and coal lease transactions, we have substantially increased our proven and probable coal reserves and non-reserve coal deposits. In addition, we have successfully grown our production through internal development projects.

We were formed in April 2010 to own and control the coal properties and related assets owned by Rhino Energy LLC. On October 5, 2010, we completed our IPO, in which we sold an aggregate of 3,730,600 common units to the public. Our common units are listed on the New York Stock Exchange under the symbol “RNO”. In connection with the IPO, Wexford contributed their membership interests in Rhino Energy LLC to us, and we issued 12,397,000 subordinated units representing limited partner interests in us and 8,666,400 common units to Wexford and issued incentive distribution rights to our general partner. Principals of Wexford Capital, including certain directors of our general partner, own the majority of the membership interests in our general partner.

In May 2012, we completed the purchase of certain rights to coal leases and surface property located in Daviess and McLean counties in western Kentucky. These coal leases and property are estimated to contain approximately 32.4 million tons of proven and probable coal reserves that are contiguous to the Green River. The property is fully permitted and provides us with access to Illinois Basin coal that is adjacent to a navigable waterway, which could allow for exports to non-U.S. customers. During 2014, we completed the initial construction of a new underground mining operation on this property. Production began in late May 2014 and the first barge shipments of coal departed from this facility in early July 2014. We have a long-term sales contract with an electric utility anchor customer and we have conducted many test shipments to potential customers that we believe could lead to additional long-term sales agreements. In addition, in June 2011 we completed the acquisition of 100% of the ownership interests in The Elk Horn Coal Company (“Elk Horn”) for approximately $119.7 million in cash consideration. Elk Horn is primarily a coal leasing company located in eastern Kentucky that provides us with coal royalty revenues, which we believe helps to diversify our income stream while limiting our direct operational risk.

We are managed by the board of directors and executive officers of our general partner. Our operations are conducted through, and our operating assets are owned by, our wholly owned subsidiary, Rhino Energy LLC, and its subsidiaries.

Coal Operations

Mining and Leasing Operations

As of December 31, 2014, we operated three mining complexes located in Central Appalachia (Tug River, Rob Fork and Deane) along with our Elk Horn coal leasing operations in Central Appalachia. In addition, we operated two mining complexes located in Northern Appalachia (Hopedale and Sands Hill). In the Western Bituminous region, we operated one mining complex located in Emery and Carbon Counties, Utah (Castle Valley). We also had one underground mine located in the Western Bituminous region in Colorado (McClane Canyon) that was permanently idled at the end of 2013 (see Note 6 of the consolidated financial statements included elsewhere in this annual report for further information). During 2014, we developed a new mining complex in the Illinois Basin, our Riveredge mine at our Pennyrile mining complex, which began production in mid-2014. The Pennyrile complex consists of one underground mine, a preparation plant and river loadout facility.

We define a mining complex as a central location for processing raw coal and loading coal into railroad cars or trucks for shipment to customers. These mining complexes include seven active preparation plants and/or loadouts, each of which receive, blend, process and ship coal that is produced from one or more of our active surface and underground mines. All of the preparation plants are modern plants that have both coarse and fine coal cleaning circuits.

The following map shows the location of our coal mining and leasing operations as of December 31, 2014 (Note: the McClane Canyon mine in Colorado was permanently idled at December 31, 2013):

Our surface mines include area mining and contour mining. These operations use truck and wheel loader equipment fleets along with large production tractors and shovels. Our underground mines utilize the room and pillar mining method. These operations generally consist of one or more single or dual continuous miner sections which are made up of the continuous miner, shuttle cars, roof bolters, feeder and other support equipment. We currently own most of the equipment utilized in our mining operations. We employ preventive maintenance and rebuild programs to ensure that our equipment is modern and well-maintained. The rebuild programs are performed either by an on-site shop or by third-party manufacturers. The mobile equipment utilized at our mining operations is scheduled for replacement on an on-going basis with new, more efficient units according to a predetermined schedule.

The following table summarizes our and the Rhino Eastern joint venture’s mining complexes and production by region as of December 31, 2014. The tons produced by the Elk Horn lessees are not included in the table below since we did not directly mine these tons, but rather collected royalty revenues from the lessees.

Region	Preparation Plants and Loadouts	Transportation to Customers(1)	Number and Type of Active Mines(2)	Tons Produced for the Year Ended December 31, 2014(3)
				(in million tons)
Central Appalachia
Tug River Complex (KY, WV)	Tug Fork & Jamboree(4)	Truck, Barge, Rail (NS)	2S	0.5
Rob Fork Complex (KY)	Rob Fork	Truck, Barge, Rail (CSX)	1U, 1S	0.4
Deane Complex (KY)	Rapid Loader	Rail (CSX)	—	0.2
Northern Appalachia
Hopedale Complex (OH)	Nelms	Truck, Rail (OHC, WLE)	1U	0.8
Sands Hill Complex (OH)	Sands Hill(5)	Truck, Barge	2S	0.2
Illinois Basin
Taylorville Field (IL)	n/a	Rail (NS)	—	—
Pennyrile Complex (KY)(6)	Preparation plant & river loadout	Barge	1U	0.2
Western Bituminous
Castle Valley Complex (UT)	Truck loadout	Truck	1U	1.1
McClane Canyon Mine (CO)(6)	n/a	Truck	—	—
Total			4U,5S	3.4
Central Appalachia
Rhino Eastern Complex (WV)(7)	Rocklick	Truck, Rail (NS, CSX)	1U	0.2

(1) NS = Norfolk Southern Railroad; CSX = CSX Railroad; OHC = Ohio Central Railroad; WLE = Wheeling & Lake Erie Railroad.

(2) Numbers indicate the number of active mines. U = underground; S = surface. All of our mines as of December 31, 2013 were company-operated.

(3) Total production based on actual amounts and not rounded amounts shown in this table.

(4) Jamboree includes only a loadout facility.

(5) Includes only a preparation plant.

(6) The McClane Canyon mine was permanently idled as of December 31, 2013.

(7) Owned by a joint venture in which we had a 51% membership interest and for which we served as manager. We dissolved the joint venture arrangement in January 2015. Amounts shown include 100% of the production.

Central Appalachia. As of December 31, 2014, we operated three mining complexes located in Central Appalachia consisting of one active underground mine and three surface mines. For the year ended December 31, 2014, the mines at our Tug River, Rob Fork and Deane mining complexes produced an aggregate of approximately 0.8 million tons of steam coal and an estimated 0.3 million tons of metallurgical coal. The underground mine at the Rhino Eastern mining complex, which was previously owned by the Rhino Eastern joint venture in which we had a 51% membership interest and for which we served as manager, produced approximately 0.2 million tons of metallurgical coal. The Rhino Eastern joint venture was dissolved in January 2015. In addition, for the year ended December 31, 2014, lessees of our Elk Horn properties produced approximately 2.9 million tons of coal.

Tug River Mining Complex. Our Tug River mining complex is located in Kentucky and West Virginia that borders the Tug River. This complex produces coal from two company operated surface mines, which includes one high-wall mining unit. Coal production from these operations is delivered to the Tug Fork preparation plant for processing and then transported by truck to the Jamboree rail loadout for blending and shipping. Coal suitable for direct-ship to customers is delivered by truck directly to the Jamboree rail loadout from the mine sites. The Tug Fork plant is a modern, 350 tons per hour preparation plant utilizing heavy media circuitry that is capable of cleaning coarse and fine coal size fractions. The Jamboree loadout is located on the Norfolk Southern Railroad and is a modern unit train, batch weigh loadout. This mining complex produced approximately 0.3 million tons of steam coal and approximately 0.2 million tons of metallurgical coal for the year ended December 31, 2014.

Rob Fork Mining Complex. Our Rob Fork mining complex is located in eastern Kentucky and currently produces coal from one company-operated surface mine and one company-operated underground mine. The Rob Fork mining complex is located on the CSX Railroad and consists of a modern preparation plant utilizing heavy media circuitry that is capable of cleaning coarse and fine coal size fractions and a unit train loadout with batch weighing equipment. The mining complex has significant blending capabilities allowing the blending of raw coals with washed coals to meet a wide variety of customers’ needs. The Rob Fork mining complex produced approximately 0.3 million tons of steam coal and 0.1 million tons of metallurgical coal for the year ended December 31, 2014.

Deane Mining Complex. Our Deane mining complex is located in eastern Kentucky and produced steam coal from one company-operated underground mine that was idle as of December 31, 2014. The infrastructure consists of a preparation plant utilizing heavy media circuitry capable of cleaning coarse and fine coal size fractions, as well as a unit train loadout facility with batch weighing equipment capable of loading in excess of 10,000 tons into railcars in approximately four hours. The facility has significant blending capabilities allowing the blending of raw coals with washed coals to meet a wide variety of customers’ needs. The Deane complex produced approximately 0.2 million tons of steam coal for the year ended December 31, 2014.

Rhino Eastern Mining Complex. The Rhino Eastern mining complex was previously owned through a joint venture where we had a 51% membership interest in, and served as manager for the mining complex located in Raleigh and Wyoming Counties, West Virginia. The joint venture was dissolved in January 2015 and an affiliate of Patriot, our previous joint venture partner, assumed ownership and operation of the mining operations.

The Rhino Eastern mining complex produced approximately 0.2 million tons of premium mid-vol metallurgical coal for the year ended December 31, 2014.

Elk Horn Coal Leasing. Elk Horn is primarily a coal leasing company located in eastern Kentucky that provides us with coal royalty revenues. For the year ended December 31, 2014, Elk Horn lessees produced approximately 2.9 million tons of coal from our Elk Horn properties.

Northern Appalachia. We operate two mining complexes located in Northern Appalachia consisting of one company-operated underground mine and two company-operated surface mines. For the year ended December 31, 2014, these mines produced an aggregate of approximately 1.0 million tons of steam coal.

Hopedale Mining Complex. The Hopedale mining complex includes an underground mine located in Hopedale, Ohio approximately five miles northeast of Cadiz, Ohio. Coal produced from the Hopedale mine is first cleaned at our Nelms preparation plant located on the Ohio Central Railroad and the Wheeling & Lake Erie Railroad and then shipped by train or truck to our customers. The infrastructure includes a full-service loadout facility. This underground mining operation produced approximately 0.8 million tons of steam coal for the year ended December 31, 2014.

Sands Hill Mining Complex. We currently operate two surface mines at our Sands Hill mining complex, located near Hamden, Ohio. The infrastructure includes a preparation plant along with a river front barge and dock facility on the Ohio River. The Sands Hill mining complex produced approximately 0.2 million tons of steam coal and approximately 0.4 million tons of limestone aggregate for the year ended December 31, 2014.

Western Bituminous Region. In January 2011, we began production at an underground mine in Emery and Carbon Counties, Utah. We also had one underground mine located in the Western Bituminous region in Colorado (McClane Canyon) that was permanently idled at the end of 2013 (see Note 6 of the consolidated financial statements included elsewhere in this annual report for further information).

Castle Valley Mining Complex. In August 2010, we completed the acquisition of certain mining assets of C.W. Mining Company out of bankruptcy. The assets acquired are located in Emery and Carbon Counties, Utah and include coal reserves and non-reserve coal deposits, underground mining equipment and infrastructure, an overland belt conveyor system, a loading facility and support facilities. We produced approximately 1.1 million tons of steam coal from one underground mine at this complex for the year ended December 31, 2014.

Illinois Basin. In May 2012, we completed the purchase of certain rights to coal leases and surface property that is contiguous to the Green River and located in Daviess and McLean counties in western Kentucky where we constructed a new underground mining complex.

Pennyrile Mining Complex. In mid-2014, we completed the initial construction of a new underground mining operation on the purchased property, referred to as our Pennyrile mining complex, which includes one underground mine, a preparation plant and river loadout facility. Production from this new underground mine began in mid-2014 and initial production was 0.2 million tons for the year ended December 31, 2014. We believe the possibility exists to expand production up to 2.0 million tons per year with further development of the mine at the Pennyrile complex.

Other Non-Mining Operations

In addition to our mining operations, we operate several subsidiaries which provide auxiliary services for our coal mining operations. Rhino Trucking provides our Kentucky coal operations with dependable, safe coal hauling to our preparation plants and loadout facilities and our southeastern Ohio coal operations with reliable transportation to our customers where rail is not available. Rhino Services is responsible for mine-related construction, site and roadway maintenance and post-mining reclamation. Through Rhino Services, we plan and monitor each phase of our mining projects as well as the post-mining reclamation efforts. We also perform the majority of our drilling and blasting activities at our company-operated surface mines in-house rather than contracting to a third party.

Other Natural Resource Assets

Oil and Gas

In addition to our coal operations, we have invested in oil and natural gas mineral rights and operations that we believe will help to diversify our income stream.

In September 2014, we made an initial investment of $5.0 million in a new joint venture, Sturgeon Acquisitions LLC (“Sturgeon”), with affiliates of Wexford Capital and Gulfport. Sturgeon subsequently acquired 100% of the outstanding equity interests of certain limited liability companies located in Wisconsin that provide frac sand for oil and natural gas drillers in the United States. We account for the investment in this joint venture and results of operations under the equity method. We recorded our proportionate portion of the operating gains for this investment during 2014 of approximately $0.4 million.

In December 2012, we made an initial investment of approximately $2.0 million in a new joint venture, Muskie Proppant LLC (“Muskie”), with affiliates of Wexford Capital. Muskie was formed to provide sand for fracking operations to drillers in the Utica Shale region and other oil and natural gas basins in the U.S. We recorded our proportionate share of the operating loss for 2014 and 2013 of approximately $0.1 million and $0.5 million, respectively. During the year ended December 31, 2014 and 2013, we contributed additional capital based upon our ownership interest to the Muskie joint venture in the amount of $0.2 million and $0.5 million, respectively. In addition, during the year ended December 31, 2013, we provided a loan based upon our ownership share to Muskie in the amount of $0.2 million, which was fully repaid in November 2014 in conjunction with our contribution of our interest in Muskie to Mammoth Energy Partners LP (“Mammoth”). In November 2014, we contributed our investment interest in Muskie to Mammoth in return for a limited partner interest in Mammoth. Mammoth was formed to own various companies that provide services to companies who engage in the exploration and development of North American onshore unconventional oil and natural gas reserves. Mammoth’s companies provide services that include completion and production services, contract land and directional drilling services and remote accommodation services.

In addition, during the second quarter of 2012 we formed a services company (“Razorback”) to provide drill pad construction services in the Utica Shale for drilling operators. Razorback has completed the construction of numerous drill pads since its inception, along with the construction of impoundments for fracking water and the construction of several access roads for operators in the Utica Shale region.

In March 2012, we made an initial investment of approximately $0.1 million in a new joint venture, Timber Wolf Terminals LLC (“Timber Wolf”), with affiliates of Wexford Capital. Timber Wolf was formed to construct and operate a condensate river terminal that will provide barge trans-loading services for parties conducting activities in the Utica Shale region of eastern Ohio. The initial investment was our proportionate minority ownership interest to purchase land for the construction site of the condensate river terminal. Timber Wolf has had no operating activities since its inception.

Limestone

Incidental to our coal mining process, we mine limestone from reserves located at our Sands Hill mining complex and sell it as aggregate to various construction companies and road builders that are located in close proximity to the mining complex when market conditions are favorable. We believe that our production of limestone provides us with an additional source of revenues at low incremental capital cost.

Coal Customers

General

Our primary customers for our steam coal are electric utilities, and the metallurgical coal we produce is sold primarily to domestic and international steel producers. Excluding results from the Rhino Eastern joint venture, for the year ended December 31, 2014, approximately 91% of our coal sales tons consisted of steam coal and approximately 9% consisted of metallurgical coal. For the year ended December 31, 2014, 100% of the Rhino Eastern joint venture’s coal sales tons consisted of metallurgical coal. For the year ended December 31, 2014, excluding results from the Rhino Eastern joint venture, approximately 81% of our coal sales tons that we produced were sold to electric utilities. The majority of our electric utility customers purchase coal for terms of one to three years, but we also supply coal on a spot basis for some of our customers. Excluding the results from the Rhino Eastern joint venture, for the year ended December 31, 2014, we derived approximately 81.0% of our total coal revenues from sales to our ten largest customers, with affiliates of our top three customers accounting for approximately 39.2% of our coal revenues for that period: NRG Energy, Inc. (fka GenOn Energy, Inc.) (15.6%); PPL Corporation (12.1%); and Intermountain Power Agency (11.5%). Additionally, pursuant to the terms of a coal purchase agreement entered into under the previous Rhino Eastern joint venture agreement, we sold 100% of Rhino Eastern’s production to an affiliate of our joint venture partner, Patriot, which controlled the amount and terms of sales of the coal produced from Rhino Eastern. As discussed earlier, the Rhino Eastern joint venture was dissolved in January 2015. Incidental to our coal mining process, we mine limestone and sell it as aggregate to various construction companies and road builders that are located in close proximity to our Sands Hill mining complex.

Coal Supply Contracts

For each of the years ended December 31, 2014 and 2013, approximately 78% and 88%, respectively, of our aggregate coal tons sold were sold through supply contracts. We expect to continue selling a significant portion of our coal under supply contracts. As of December 31, 2014, we had commitments under supply contracts to deliver annually scheduled base quantities as follows:

Year	Tons (in thousands)	Number of customers
2015	3,260	13
2016	2,121	5
2017	1,100	2

Some of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

Quality and volumes for the coal are stipulated in coal supply contracts, and in some instances buyers have the option to vary annual or monthly volumes. Most of our coal supply contracts contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as heat content, sulfur, ash, hardness and ash fusion temperature. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contracts. Some of our contracts specify approved locations from which coal may be sourced. Some of our contracts set out mechanisms for temporary reductions or delays in coal volumes in the event of a force majeure, including events such as strikes, adverse mining conditions, mine closures, or serious transportation problems that affect us or unanticipated plant outages that may affect the buyers.

The terms of our coal supply contracts result from competitive bidding procedures and extensive negotiations with customers. As a result, the terms of these contracts, including price adjustment features, price re-opener terms, coal quality requirements, quantity parameters, permitted sources of supply, future regulatory changes, extension options, force majeure, termination and assignment provisions, vary significantly by customer.

Coal Lease Agreements

With respect to our coal leasing operations, we enter into leases with coal mine operators granting them the right to mine and sell coal from our Elk Horn properties in exchange for a royalty payment. Generally, the lease terms provide us with a royalty fee of 6% to 9% of the gross sales price of the coal, with a minimum royalty fee ranging from $1.85 to $4.75 per ton. The terms of such leases vary from five years to the life of the reserves. A minimum royalty is required annually or monthly whether or not the property is mined.

Transportation

We ship coal to our customers by rail, truck or barge. For the year ended December 31, 2014, the majority of our coal sales tonnage was shipped by rail. The majority of our coal is transported to customers by either the CSX Railroad or the Norfolk Southern Railroad in eastern Kentucky and by the Ohio Central Railroad or the Wheeling & Lake Erie Railroad in Ohio. In addition, in southeastern Ohio, we use our own trucking operations to transport coal to our customers where rail is not available. We use third-party trucking to transport coal to our customers in Utah. For our new Pennyrile complex in western Kentucky, coal is transported to our customers via barge from our river loadout on the Green River located on our Pennyrile mining complex. In addition, coal from certain of our Central Appalachia and southern Ohio mines is located within economical trucking distance to the Big Sandy River and/or the Ohio River and can be transported by barge. It is customary for customers to pay the transportation costs to their location.

We believe that we have good relationships with rail carriers and truck companies due, in part, to our modern coal-loading facilities at our loadouts and the working relationships and experience of our transportation and distribution employees.

Suppliers

Principal supplies used in our business include diesel fuel, explosives, maintenance and repair parts and services, roof control and support items, tires, conveyance structures, ventilation supplies and lubricants. We use third-party suppliers for a significant portion of our equipment rebuilds and repairs, drilling services and construction.

We have a centralized sourcing group for major supplier contract negotiation and administration, for the negotiation and purchase of major capital goods and to support the mining and coal preparation plants. We are not dependent on any one supplier in any region. We promote competition between suppliers and seek to develop relationships with those suppliers whose focus is on lowering our costs. We seek suppliers who identify and concentrate on implementing continuous improvement opportunities within their area of expertise.

Competition

The coal industry is highly competitive. There are numerous large and small producers in all coal producing regions of the United States and we compete with many of these producers. Our main competitors include Alliance Resource Partners LP, Alpha Natural Resources, Inc., Arch Coal, Inc., Booth Energy Group, CONSOL Energy Inc., Murray Energy Corporation, Foresight Energy LP, Westmoreland Resource Partners, LP, Patriot and Bowie Resource Partners LLC.

The most important factors on which we compete are coal price, coal quality and characteristics, transportation costs and the reliability of supply. Demand for coal and the prices that we will be able to obtain for our coal are closely linked to coal consumption patterns of the domestic electric generation industry and international consumers. These coal consumption patterns are influenced by factors beyond our control, including demand for electricity, which is significantly dependent upon economic activity and summer and winter temperatures in the United States, government regulation, technological developments and the location, availability, quality and price of competing sources of fuel such as natural gas, oil and nuclear, and alternative energy sources such as hydroelectric power and wind power.

Regulation and Laws

Our operations are subject to regulation by federal, state and local authorities on matters such as:

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employee health and safety;

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mine permits and other licensing requirements;

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air quality standards;

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water quality standards;

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storage, treatment, use and disposal of petroleum products and other hazardous substances;

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plant and wildlife protection;

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reclamation and restoration of mining properties after mining is completed;

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the discharge of materials into the environment, including waterways or wetlands;

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storage and handling of explosives;

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wetlands protection;

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surface subsidence from underground mining;

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the effects, if any, that mining has on groundwater quality and availability; and

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legislatively mandated benefits for current and retired coal miners.

In addition, many of our customers are subject to extensive regulation regarding the environmental impacts associated with the combustion or other use of coal, which could affect demand for our coal. The possibility exists that new laws or regulations, or new interpretations of existing laws or regulations, may be adopted that may have a significant impact on our mining operations, oil and natural gas investments, or our customers’ ability to use coal.

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 occur from time to time. Violations, including violations of any permit or approval, can result in substantial civil and in severe cases, criminal fines and penalties, including revocation or suspension of mining permits. None of the violations to date have had a material impact on our operations or financial condition.

While it is not possible to quantify the costs of compliance with applicable federal and state laws and regulations, those costs have been and are expected to continue to be significant. Nonetheless, capital expenditures for environmental matters have not been material in recent years. We have accrued for the present value of 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 reclamation 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 determined these accruals to be insufficient. Compliance with these laws and regulations has substantially increased the cost of coal mining for all domestic coal producers. Most of the statutes discussed below apply to exploration and development activities associated with our oil and natural gas investments as well, and therefore we do not present a separate discussion of statutes related to those activities.

Mining Permits and Approvals

Numerous governmental permits or approvals are required for coal mining operations. When we apply for these permits and approvals, we are often required to assess the effect or impact that any proposed production of coal may have upon the environment. The permit application requirements may be costly and time consuming, and may delay or prevent commencement or continuation of mining operations in certain locations. Future laws and regulations may emphasize more heavily the protection of the environment and, as a consequence, our activities may be more closely regulated. Laws and regulations, as well as future interpretations or enforcement of existing laws and regulations, 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. The permitting process for certain mining operations can extend over several years, and can be subject to judicial challenge, including by the public. Some required mining permits are becoming increasingly difficult to obtain in a timely manner, or at all. We may experience difficulty and/or delay in obtaining mining permits in the future.

Regulations 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 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.

Mine Health and Safety Laws

Stringent safety and health standards have been in effect since the adoption of the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health Act of 1977 (the “Mine Act”), 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 equipment used in mining operations and other matters. The Mine Safety and Health Administration (“MSHA”) monitors compliance with these laws and regulations. In addition, the states where we operate also have state programs for mine safety and health regulation and enforcement. Federal and state safety and health regulations affecting the coal industry are complex, rigorous and comprehensive, and have a significant effect on our operating costs.

The Mine Act is a strict liability statute that requires mandatory inspections of surface and underground coal mines and requires the issuance of enforcement action when it is believed that a standard has been violated. A penalty is required to be imposed for each cited violation. Negligence and gravity assessments result in a cumulative enforcement scheme that may result in the issuance of an order requiring the immediate withdrawal of miners from the mine or shutting down a mine or any section of a mine or any piece of mine equipment. The Mine Act contains criminal liability provisions. For example, criminal liability may be imposed for corporate operators who knowingly or willfully authorize, order or carry out violations. The Mine Act also provides that civil and criminal penalties may be assessed against individual agents, officers and directors who knowingly authorize, order or carry out violations.

We have developed a health and safety management system that, among other things, educates our employees about health and safety requirements including those arising under federal and state laws that apply to our mines. In addition, our health and safety management system tracks the performance of each operational facility in meeting the requirements of safety laws and company safety policies. As an example of the resources we allocate to health and safety matters, our safety management system includes a company-wide safety director and local safety directors who oversee safety and compliance at operations on a day-to-day basis. We continually monitor the performance of our safety management system and from time-to-time modify that system to address findings or reflect new requirements or for other reasons. We have even integrated safety matters into our compensation and retention decisions. For instance, our bonus program includes a meaningful evaluation of each eligible employee’s role in complying with, fostering and furthering our safety policies.

We evaluate a variety of safety-related metrics to assess the adequacy and performance of our safety management system. For example, we monitor and track performance in areas such as “accidents, reportable accidents, lost time accidents and the lost-time accident frequency rate” and a number of others. Each of these metrics provides insights and perspectives into various aspects of our safety systems and performance at particular locations or mines generally and, among other things, can indicate where improvements are needed or further evaluation is warranted with regard to the system or its implementation. An important part of this evaluation is to assess our performance relative to certain national benchmarks.

Our non-fatal days lost time incidence rate for all operations for the year ended December 31, 2014 was 1.63 as compared to the most recent national average of 2.42, as reported by MSHA, or 32.76% below this national average. Non-fatal days lost incidence rate is an industry standard used to describe occupational injuries that result in loss of one or more days from an employee’s scheduled work. In addition, for the year ended December 31, 2014 our average MSHA violations per inspection day was 0.46 as compared to the most recent national average of 0.62 violations per inspection day for coal mining activity as reported by MSHA, or 25.80% below this national average.

Mining accidents in the last several years in West Virginia, Kentucky and Utah have received national attention and instigated responses at the state and national levels that have resulted in increased scrutiny of current safety practices and procedures at all mining operations, particularly underground mining operations. More stringent mine safety laws and regulations promulgated by these states and the federal government have included increased sanctions for non-compliance. For example, in 2006, the Mine Improvement and New Emergency Response Act of 2006, or MINER Act, was enacted. The MINER Act significantly amended the Mine Act, requiring improvements in mine safety practices, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection and enforcement activities. Since passage of the MINER Act, enforcement scrutiny has increased, including more inspection hours at mine sites, increased numbers of inspections and increased issuance of the number and the severity of enforcement actions and related penalties. Other states have proposed or passed similar bills, resolutions or regulations addressing mine safety practices. Moreover, workplace accidents, such as the April 5, 2010, Upper Big Branch Mine incident, have resulted in more inspection hours at mine sites, increased number of inspections and increased issuance of the number and severity of enforcement actions and the passage of new laws and regulations. These trends are likely to continue.

Indeed, in 2013, MSHA began implementing its recently released Pattern of Violation (“POV”) regulations under the Mine Act. Under this regulation, MSHA eliminated the ninety (90) day window to take corrective action and engage in mitigation efforts for mine operators who met certain initial POV screening criteria. Additionally, MSHA will make POV determinations based upon enforcement actions as issued, rather than enforcement actions that have been rendered final following the opportunity for administrative or judicial review. After a mine operator has been placed on POV status, MSHA will thereafter issue an order withdrawing miners from the area affected by any enforcement action designated by MSHA as posing a significant and substantial, or S&S, hazard to the health and/or safety of miners. Further, once designated as a POV mine, a mine operator can be removed from POV status only upon: (1) a complete inspection of the entire mine with no S&S enforcement actions issued by MSHA; or (2) no POV-related withdrawal orders being issued by MSHA within ninety (90) days of the mine operator being placed on POV status. Although it remains to be seen how these new regulations will ultimately affect production at our mines, they are consistent with the trend of more stringent enforcement.

From time to time, certain portions of individual mines have been required to suspend or shut down operations temporarily in order to address a compliance requirement or because of an accident. For instance, MSHA issues orders pursuant to Section 103(k) that, among other things, call for operations in the area of the mine at issue to suspend operations until compliance is restored. Likewise, if an accident occurs within a mine, the MSHA requirements call for all operations in that area to be suspended until the circumstance leading to the accident has been resolved. During the fiscal year ended December 31, 2014 (as in earlier years), we received such orders from government agencies and have experienced accidents within our mines requiring the suspension or shutdown of operations in those particular areas until the circumstances leading to the accident have been resolved. While the violations or other circumstances that caused such an accident were being addressed, other areas of the mine could and did remain operational. These circumstances did not require us to suspend operations on a mine-wide level or otherwise entail material financial or operational consequences for us. Any suspension of operations at any one of our locations that may occur in the future may have material financial or operational consequences for us.

It is our practice to contest notices of violations in cases in which we believe we have a good faith defense to the alleged violation or the proposed penalty and/or other legitimate grounds to challenge the alleged violation or the proposed penalty. In December 2008 and March 2009, MSHA assessed proposed penalties in excess of $100,000 with regard to three separate notices of violation, all of which relate to our operations at Mine 28. Each of these notices of violation alleged an “unwarrantable failure” under the Mine Act with specific regard to the accumulation of combustible materials. The combustible materials typically underlying such citations are coal, loose coal, and float coal dust. We have contested these violations on grounds that the underlying circumstances did not support the issuance of a notice of violation and/or the gravity of the proposed penalty. These contests are still pending and we cannot predict the outcome of these proceedings or assure you that the fines and penalties will not be assessed in full against us. These alleged violations were abated at the time or immediately after the notices of violation were issued, and we have not been issued any notices of violation from MSHA proposing a penalty in excess of $100,000 since March 2009.

We exercise substantial efforts toward achieving compliance at our mines. In light of the recent citations issued with respect to our mines, we have further increased our focus with regard to health and safety at all of our mines and at Mine 28 and Eagle #1 Mine in particular. These efforts include hiring additional skilled personnel, providing training programs, hosting quarterly safety meetings with MSHA personnel and making capital expenditures in consultation with MSHA aimed at increasing mine safety. We believe that these efforts have contributed, and continue to contribute, positively to safety and compliance at our mines. In Item 4. Mine Safety Disclosure and in Exhibit 95 to this Annual Report on Form 10-K, we provide additional details on how we monitor safety performance and MSHA compliance, as well as provide the mine safety disclosures required pursuant to Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act.

Black Lung Laws

Under the Black Lung Benefits Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, coal mine operators must make payments of black lung benefits to current and former coal miners with black lung disease, some survivors of a miner who dies from this disease, and to fund a trust fund for the payment of benefits and medical expenses to claimants who last worked in the industry prior to January 1, 1970. To help fund these benefits, a tax is levied 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. This excise tax does not apply to coal that is exported outside of the United States. In 2014, we recorded approximately $3.0 million of expense related to this excise tax.

The Patient Protection and Affordable Care Act includes significant changes to the federal black lung program including an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim and establishes a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition. These changes could have a material impact on our costs expended in association with the federal black lung program. We may also be liable under state laws for black lung claims that are covered through either insurance policies or state programs.

Workers’ Compensation

We are required to compensate employees for work-related injuries under various state workers’ compensation laws. The states in which we operate consider changes in workers’ compensation laws from time to time. Our costs will vary based on the number of accidents that occur at our mines and other facilities, and our costs of addressing these claims. We are insured under the Ohio State Workers Compensation Program for our operations in Ohio. Our remaining operations, including Central Appalachia and the Western Bituminous region, are insured through Rockwood Casualty Insurance Company.

Surface Mining Control and Reclamation Act (“SMCRA”)

SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining, including the surface effects of underground coal mining. SMCRA 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, reclamation 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 that we restore the surface to approximate the original contours as soon as practicable upon the completion of surface mining operations. The mine operator must submit a bond or otherwise secure the performance of these reclamation obligations. Mine operators can also be responsible 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 long-wall mining and possibly other mining operations. 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 prior to SMCRA’s adoption in 1977. The maximum tax for the period from October 1, 2012 through September 30, 2021, has been decreased to 28 cents per ton on surface mined coal and 12 cents per ton on underground mined coal. As of December 31, 2014, we had accrued approximately $29.9 million 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 abandoned mine drainage control on a statewide basis.

After a mine application is submitted, public notice or advertisement of the proposed permit action is required, which is followed by a public comment period. It is not uncommon for a SMCRA mine permit application to take over two years to prepare and review, depending on the size and complexity of the mine, and another two years or even longer for the permit to be issued. The variability in time frame required to prepare the application and issue the permit can be attributed primarily to the various regulatory authorities’ discretion in the handling of comments and objections relating to the project received from the general public and other agencies. Also, it is not uncommon for a permit to be delayed as a result of judicial challenges related to the specific permit or another related company’s permit.

Federal laws and regulations also provide that a mining permit or modification can be delayed, refused or revoked if owners of specific percentages of ownership interests or controllers (i.e., officers and directors or other entities) of the applicant have, or are affiliated with another entity that has outstanding violations of SMCRA or state or tribal programs authorized by SMCRA. This condition is often referred to as being “permit blocked” under the federal Applicant Violator Systems, or AVS. Thus, non-compliance with SMCRA can provide the bases to deny the issuance of new mining permits or modifications of existing mining permits, although we know of no basis by which we would be (and we are not now) permit-blocked.

In addition, a February 2014 decision by the U.S. District Court for the District of Columbia invalidated the Office of Surface Mining Reclamation and Enforcement’s (“OSM”) 2008 Stream Buffer Zone Rule, which prohibited mining disturbances within 100 feet of streams, subject to various exemptions. In December 2014, OSM reinstated the 1983 version of the Stream Buffer Zone regulations, which offer fewer exemptions to the 100 foot buffer requirement, as a direct final rule. In 2009, OSM published an advance notice of proposed rulemaking to revise the Stream Buffer Zone Rule through a more protective regulatory strategy called the Stream Protection Rule, which would prohibit mining disturbances within 100 feet of streams if there would be a negative effect on water quality. The Stream Protection Rule has not yet been proposed or finalized. OSM is currently developing an environmental impact statement (“EIS”) for use in drafting the anticipated Stream Protection Rule. A notice of proposed rulemaking for the Stream Protection Rule is expected to be issued in April 2015. We are unable to predict the impact, if any, of these actions by the OSM, although the actions potentially could result in additional delays and costs associated with obtaining permits, prohibitions or restrictions relating to mining activities near streams, and additional enforcement actions. In addition, Congress has proposed, and may in the future propose, legislation to restrict the placement of mining material in streams. The requirements of the new Stream Protection Rule or future legislation, when adopted, will likely be stricter than the prior Stream Buffer Zone Rule to further protect streams from the impact of surface mining, and may adversely affect our business and operations.

Surety Bonds

Federal and state laws require a mine operator to secure the performance of its reclamation obligations required under SMCRA through the use of surety bonds or other approved forms of performance security to cover the costs the state would incur if the mine operator were unable to fulfill its obligations. It has become increasingly difficult for mining companies 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 favorable. It is possible that surety bonds issuers may refuse 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 our ability to produce coal, which could affect our profitability and cash flow.

As of December 31, 2014, we had approximately $70.2 million in surety bonds outstanding to secure the performance of our reclamation obligations. We may be required to increase these amounts as a result of recent developments in West Virginia and Kentucky. In 2011, West Virginia passed legislation that provides for a minimum incremental bonding rate in lieu of a minimum bond amount that applies regardless of acreage. In addition, the Kentucky Department for Natural Resources and the Office of Surface Mining Reclamation and Enforcement Lexington Field Office executed an Action Plan for Improving the Adequacy of Kentucky Performance Bond Amounts, which provides for, among other things, revised bond computation protocols.

Air Emissions

The federal Clean Air Act, or the CAA, and similar state and local laws and regulations, which regulate emissions into the air, affect coal mining operations both directly and indirectly. The CAA directly impacts our coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, on sources that emit various hazardous and non-hazardous air pollutants. The CAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants and other industrial consumers of coal, including air emissions of sulfur dioxide, nitrogen oxides, particulates, mercury and other compounds. There have been a series of recent federal rulemakings that are focused on emissions from coal-fired electric generating facilities. Installation of additional emissions control technology and additional measures required under laws and regulations related to air emissions will make it more costly to operate coal-fired power plants and possibly other facilities that consume coal and, depending on the requirements of individual state implementation plans, or SIPs, could make coal a less attractive fuel alternative in the planning and building of power plants in the future.

In addition to the greenhouse gas (“GHG”) regulations discussed below, air emission control programs that affect our operations, directly or indirectly, include, but are not limited to, the following:

	●	The EPA’s Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric generating facilities. Sulfur dioxide is a by-product of coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility’s sulfur dioxide emissions in that year. Affected facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions. In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the EPA’s Acid Rain Program by switching to lower sulfur fuels, installing pollution control devices such as flue gas desulfurization systems, or “scrubbers,” or by reducing electricity generating levels.

	●	The EPA has promulgated rules, referred to as the “NOx SIP Call,” that require coal-fired power plants in 22 eastern states and Washington D.C. to make substantial reductions in nitrogen oxide emissions in an effort to reduce the impacts of ozone transport between states. As a result of the program, many power plants have been or will be required to install additional emission control measures, such as selective catalytic reduction devices.

	●	Additionally, in March 2005, EPA issued the final Clean Air Interstate Rule, or CAIR, which would have reduced nitrogen oxide and sulfur dioxide emissions in 28 eastern states and Washington, D.C. pursuant to a cap and trade program similar to the system now in effect for acid rain. A December 2008 court decision found flaws in CAIR, but kept CAIR requirements in place temporarily while directing the EPA to issue a replacement rule.

	●	In July 2011, EPA finalized a rule intended to replace CAIR called the Cross-State Air Pollution Rule, or CSAPR, which requires 28 states in the eastern half of the US to reduce power plant emissions that cross state lines and contribute to ground-level ozone and fine particle pollution in other states. CSAPR was scheduled to replace CAIR starting January 2012. However, the U.S. Court of Appeals for the D.C. Circuit vacated CSAPR in August 2012, in a 2 to 1 decision, concluding that the rule was beyond the EPA’s statutory authority. The EPA petitioned for en banc review of that decision by the entire U.S. Court of Appeals for the District of Columbia Circuit, but the petition was denied in January 2013. The U.S. Supreme Court granted certiorari and in April 2014, the Court found that the EPA was complying with statutory requirements when it issued CSAPR and reversed the D.C. Circuit’s vacation of CSAPR. Based on further proceedings in the lower court, in November 2014, EPA issued an interim final rule reconciling the CSAPR rule with the court’s order, which calls for Phase 1 implementation in 2015 and Phase 2 implementation in 2017. However, other legal challenges to CSAPR remain to be heard in the D.C. Circuit litigation, which are still pending. For states to meet their requirements under CSAPR, a number of coal-fired power plants will likely need to be retired, rather than be retrofitted with the necessary emission control technologies, reducing the demand for steam coal.

	●	In February 2012, the EPA formally adopted its “MATS rule,” which imposes a new suite of limits on coal- and oil-fired electric generating unit (“EGU”) emissions of mercury, other metals, acid gases, and organic air toxics. On July 20, 2012, the EPA announced that it is reviewing technical information that is focused on pollution limits under the MATS rule, based on new information provided by industry stakeholders after the rule was finalized. In March 2013, EPA finalized the MATS rule for new power plants, principally adjusting emissions limits to levels attainable by existing control technologies. The D.C. Circuit upheld various portions of the rulemaking in two separate decisions issued in March and April 2014, respectively. In November 2014, the U.S. Supreme Court granted certiorari to review the D.C. Circuit decision. These requirements could significantly increase our customers’ costs and cause them to reduce their demand for coal, which may materially impact our results or operations. Some utilities have been moving forward with installation of equipment necessary to comply with MATS, and the EPA and states have been granting additional time beyond the 2015 deadline (but no more than one extra year) for facilities that need more time to upgrade and complete those installations. The rule could result in the retirement of certain older coal plants.

	●	In addition, in January 2013, the EPA issued final MACT standards for several classes of boilers and process heaters, including large coal-fired boilers and process heaters (Boiler MACT), which require significant reductions in the emission of particulate matter, carbon monoxide, hydrogen chloride, dioxins and mercury. Like MATS, Boiler MACT imposes stricter limitations on mercury emissions than those vacated in CAMR. Business and environmental groups have filed legal challenges in federal appeals court and have petitioned EPA to reconsider the rule. EPA has granted petitions for reconsideration for certain issues and published its reconsideration, which seeks additional public comment, in December 2014. However, if Boiler MACT is upheld as previously finalized, EPA estimates the rule will affect 1,700 existing major source facilities with an estimated 14,316 boilers and process heaters. Some owners will make capital expenditures to retrofit boilers and process heaters, while a number of boilers and process heaters will be prematurely retired. The retirements are likely to reduce the demand for coal. The impact of the regulations will depend on the outcome of these legal challenges and cannot be determined at this time.

	●	The EPA has adopted new, more stringent national air quality standards, or NAAQS, for ozone, fine particulate matter, nitrogen dioxide and sulfur dioxide. As a result, some states will be required to amend their existing SIPs to attain and maintain compliance with the new air quality standards. For example, in June 2010, the EPA issued a final rule setting forth a more stringent primary NAAQS applicable to sulfur dioxide. The rule also modifies the monitoring increment for the sulfur dioxide standard, establishing a 1-hour standard, and expands the sulfur dioxide monitoring network. Initial non-attainment determinations related to the 2010 sulfur dioxide rule were published in August 2013 with an effective date in October 2013. Determinations on remaining areas of the U.S. have to be made. States with non-attainment areas will have until April 2015 to submit SIP revisions which must meet the modified standard by summer 2017. For all other areas, states will be required to submit “maintenance” SIPs. EPA finalized its PM2.5 NAAQS designations in December 2014, although EPA deferred making designations for several areas due to data validity issues. Individual states must now identify the sources of PM2.5 emissions and develop emission reduction plans, which may be state-specific or regional in scope. Nonattainment areas must meet the revised standard no later than 2021. In November 2014, EPA also proposed a revision of the existing NAAQS for ozone, making it more stringent. Significant additional emissions control expenditures will likely be required at coal-fired power plants and coke plants to meet the new standards, which are expected to be finalized in 2015. Nitrogen oxides, which are a by-product of coal combustion, can lead to the creation of ozone. Because coal mining operations and coal-fired electric generating facilities emit particulate matter and sulfur dioxide, our mining operations and customers could be affected when the standards are implemented by the applicable states.

	●	In June 2005, the EPA amended its regional haze program to improve visibility in national parks and wilderness areas. Affected states were required to develop SIPs by December 2007 that, among other things, identifies facilities that will have to reduce emissions and comply with stricter emission limitations. This program may restrict construction of new coal-fired power plants where emissions are projected to reduce visibility in protected areas. In addition, this program may require certain existing coal-fired power plants to install emissions control equipment to reduce haze-causing emissions such as sulfur dioxide, nitrogen oxide, and particulate matter. Demand for our steam coal could be affected when these standards are implemented by the applicable states.

The Department of Justice, on behalf of the EPA, has filed lawsuits against a number of coal-fired electric generating facilities alleging violations of the new source review provisions of the CAA. The EPA has alleged that certain modifications have been made to these facilities without first obtaining certain permits issued under the new source review program. Several of these lawsuits have settled, but others remain pending. Depending on the ultimate resolution of these cases, demand for our coal could be affected.

Non-government organizations have also petitioned EPA to regulate coal mines as stationary sources under the Clean Air Act. On May 13, 2014, the D.C. Circuit in WildEarth Guardians v. United States Environmental Protection Agency upheld EPA’s denial of one such petition. On July 18, 2014, the D.C. Circuit denied a petition to rehear that case en banc. If such efforts are successful, emissions of these or other materials associated with our mining operations could become subject to further regulation pursuant to existing laws such as the CAA. In that event, we may be required to install additional emissions control equipment or take other steps to lower emissions associated with our operations, thereby reducing our revenues and adversely affecting our operations.

Carbon Dioxide Emissions

One by-product of burning coal is carbon dioxide, which EPA considers a greenhouse gas (“GHG”) and a major source of concern with respect to climate change and global warming.

Future regulation of GHG in the United States could occur pursuant to future U.S. treaty commitments, new domestic legislation that may impose a carbon emissions tax or establish a cap-and-trade program or regulation by the EPA. The EPA also recently proposed new source performance standards for GHG for new coal and oil-fired power plants, which could require partial carbon capture and sequestration to comply. In addition, in October 2013, the U.S. Supreme Court granted certiorari to hear arguments related to a combination of several petitions challenging EPA’s approach to CO2 regulation. In addition, passage of any comprehensive federal climate change and energy legislation could impact the demand for coal. Any reduction in the amount of coal consumed by North American electric power generators could reduce the price of coal that we mine and sell, thereby reducing our revenues and materially and adversely affecting our business and results of operations.

Even in the absence of new federal legislation, the EPA has begun to regulate GHG emissions pursuant to the CAA based on the April 2007 United States Supreme Court ruling in Massachusetts, et al. v. EPA that the EPA has authority to regulate carbon dioxide emissions. EPA’s GHG regulations include:

(1) the October 2009 Mandatory Reporting Rule, which requires GHG sources above certain thresholds to monitor and report their emissions;

(2) the December 2009 “Endangerment Finding,” determining that air pollution from six GHGs endangers public health and welfare, and that mobile sources cause or contribute to that air pollution;

(3) the May 2010 “Tailpipe Rule,” issued jointly with the National Highway Traffic Safety Administration setting GHG emission and fuel economy standards for new light-duty vehicles;

(4) the June 2010 “Final Mandatory Reporting of GHGs Rule,” requiring all stationary sources that emit more than 25,000 tons of GHGs per year to collect and report to the EPA data regarding such emissions. This rule affects many of our customers, as well as additional source categories, including all underground mines subject to quarterly methane sampling by MSHA. Underground mines subject to this rule were required to begin monitoring GHG emissions on January 1, 2011 and must begin reporting to the EPA on March 31, 2012.

(5) the April 2010 “Timing Rule,” concluding that stationary source regulation under Titles I and V of the CAA (involving Prevention of Significant Deterioration regulations and operating permits, respectively) must regulate GHG emissions beginning when such emissions are subject to controls under the mobile source provisions of the Act;

(6) the June 2010 “Tailoring Rule,” temporarily exempting small stationary sources from PSD and Title V requirements through regulations modifying the CAA’s emissions thresholds; and

(7) the December 2010 “SIP Call” rule, finding 13 SIPs inadequate because they did not regulate GHGs from stationary sources, and directing those States to correct the inadequacies or face federalization of their permitting programs.

All of these regulations are subject to legal challenges, but the D.C. Circuit has generally refused to stay their implementation while the challenges are pending. On June 26, 2012, the U.S. Court of Appeals for the District of Columbia Circuit rejected challenges to the Tailoring Rule and other EPA rules relating to the regulation of GHGs under the CAA. In March 2012, the EPA proposed New Source Performance Standards (“NSPS”) for carbon dioxide emissions from new and modified EGUs. EPA revised its proposal in September 2013, and intends to finalize the rule in mid-summer 2015. The final NSPS, if promulgated along the lines proposed, would pose significant challenges for the construction of new coal-fired power plants and could result in a decrease in U.S. demand for steam coal.

Additionally, in June 2014, the EPA further proposed new regulations limiting carbon dioxide emissions from existing power generation facilities. The plan sets a national carbon pollution standard that is projected to cut emissions produced by United States power plants by 2030, by 30% from 2005 levels. Although states can choose to rely on the four measures set by the EPA to meet this goal, the states themselves will ultimately decide the means to use. States can develop individual plans, or they can collaborate with other states. These measures states may employ include: renewable energy standards, efficiency improvements at plants, switching to natural gas, transmission efficiency improvements, energy storage technology, expanding renewables or nuclear, and energy conservation programs. Under the proposed rule, states will have until June 2016 to submit final plans, although extensions may be allotted if needed. The final rule is expected to be issued by mid-summer 2015 and the emission reductions are scheduled to commence in 2020. An Ohio-based coal company has already filed a legal challenge to the proposed rulemaking in the D.C. Circuit, and nine states have joined as amici.

Many states and regions have adopted greenhouse gas initiatives and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of greenhouse gases by certain facilities, including coal-fired electric generating facilities. For example, in 2005, ten northeastern states entered into the Regional Greenhouse Gas Initiative agreement, or RGGI, calling for implementation of a cap and trade program aimed at reducing carbon dioxide emissions from power plants in the participating states. The members of RGGI have established in statute and/or regulation a carbon dioxide trading program. Auctions for carbon dioxide allowances under the program began in September 2008. Though New Jersey withdrew from RGGI in 2011, since its inception, several additional northeastern states and Canadian provinces have joined as participants or observers.

Following the RGGI model, five Western states launched the Western Regional Climate Action Initiative to identify, evaluate and implement collective and cooperative methods of reducing greenhouse gases in the region to 15% below 2005 levels by 2020. These states were joined by two additional states and four Canadian provinces and became collectively known as the Western Climate Initiative Partners. However, in November 2011, six states withdrew, leaving California and the four Canadian provinces as members. At a January 12, 2012 stakeholder meeting, this group confirmed a commitment and timetable to create the largest carbon market in North America and provide a model to guide future efforts to establish national approaches in both Canada and the U.S. to reduce GHG emissions. It is likely that these regional efforts will continue.

Our customers’ coal-fired coal plants have also come under additional scrutiny with respect to GHG emissions. There have been an increasing number of protests and challenges to the permitting of new coal-fired power plants by environmental organizations and state regulators for concerns related to greenhouse gas emissions. For instance, in October 2007, state regulators in Kansas denied an air emissions construction permit for a new coal-fueled power plant based on the plant’s projected emissions of carbon dioxide. Other state regulatory authorities have also rejected the construction of new coal-fueled power plants based on the uncertainty surrounding the potential costs associated with GHG emissions from these plants under future laws limiting the emissions of carbon dioxide. In addition, several permits issued to new coal-fired power plants without limits on GHG emissions have been appealed to the EPA’s Environmental Appeals Board. In addition, over 30 states have adopted mandatory “renewable portfolio standards,” which require electric utilities to obtain a certain percentage of their electric generation portfolio from renewable resources by a certain date. These standards range generally from 10% to 30%, over time periods that generally extend from the present until between 2020 and 2030. Other states may adopt similar requirements, and federal legislation is a possibility in this area. To the extent these requirements affect our current and prospective customers; they may reduce the demand for coal-fired power, and may affect long-term demand for our coal. Finally, a federal appeals court has allowed a lawsuit pursuing federal common law claims to proceed against certain utilities on the basis that they may have created a public nuisance due to their emissions of carbon dioxide, while a second federal appeals court dismissed a similar case on procedural grounds. On June 20, 2011, the U.S. Supreme Court ruled unanimously in AEP v. Connecticut that the authority to regulate large stationary sources of GHG emissions granted to the EPA under the CAA displaces federal common law public nuisance claims against those sources.

If mandatory restrictions on carbon dioxide emissions are imposed, the ability to capture and store large volumes of carbon dioxide emissions from coal-fired power plants may be a key mitigation technology to achieve emissions reductions while meeting projected energy demands. A number of recent legislative and regulatory initiatives to encourage the development and use of carbon capture and storage technology have been proposed or enacted. On February 3, 2010, President Obama sent a memorandum to the heads of fourteen Executive Departments and Federal Agencies establishing an Interagency Task Force on Carbon Capture and Storage (“CCS”). The goal was to develop a comprehensive and coordinated Federal strategy to speed the commercial development and deployment of clean coal technologies. On August 12, 2010, the Task Force delivered a series of recommendations on overcoming the barriers to the widespread, cost-effective deployment of CCS within ten years. The report concludes that CCS can play an important role in domestic GHG emissions reductions while preserving the option of using abundant domestic fossil energy resources. The EPA also recently proposed new source performance standards for GHG for new coal and oil-fired power plants, which could require partial carbon capture and sequestration to comply. However, widespread cost-effective deployment of CCS will occur only if the technology is commercially available at economically competitive prices and supportive national policy frameworks are in place.

Clean Water Act

The Federal Clean Water Act, or the CWA, and similar state and local laws and regulations affect coal mining operations by imposing restrictions on the discharge of pollutants, including dredged or fill material, into waters of the U.S. The CWA establishes in-stream water quality and treatment standards for wastewater discharges that are applied to wastewater dischargers through Section 402 National Pollutant Discharge Elimination System, or NPDES, permits. Regular monitoring, as well as compliance with reporting requirements and performance standards, are preconditions for the issuance and renewal of Section 402 NPDES permits. Individual permits or general permits under Section 404 of the CWA are required to discharge dredged or fill materials into waters of the U.S. including wetlands, streams, and other areas meeting the regulatory definition. Our surface coal mining and preparation plant operations typically require such permits to authorize activities such as the creation of slurry ponds, stream impoundments, and valley fills. The EPA, or a state that has been delegated such authority by the EPA, issues NPDES permits for the discharge of pollutants into navigable waters, while the U.S. Army Corps of Engineers, or the Corps, issues dredge and fill permits under Section 404 of the CWA. Where Section 402 NPDES permitting authority has been delegated to a state, the EPA retains a limited oversight role. The CWA also gives the EPA an oversight role in the Section 404 permitting program, including drafting substantive rules governing permit issuance by the Corps, providing comments on proposed permits, and, in some cases, exercising the authority to delay or pre-empt Corps issuance of a Section 404 permit. The EPA has recently asserted these authorities more forcefully to question, delay, and prevent issuance of some Section 402 and 404 permits for surface coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits.

For instance, even though the Commonwealth of Kentucky and the State of West Virginia have been delegated the authority to issue NPDES permits for coal mines in those states, the EPA is taking a more active role in its review of NPDES permit applications for coal mining operations in Appalachia. The EPA issued final guidance on July 21, 2011 that encouraged EPA Regions 3, 4 and 5 to object to the issuance of state program NPDES permits where the Region does not believe that the proposed permit satisfies the requirements of the CWA and with regard to state issued general Section 404 permits, support the previously drafted Enhanced Coordination Process (“ECP”) among the EPA, the Corps, and the U.S. Department of the Interior for issuing Section 404 permits, whereby the EPA undertook a greater level of review of certain Section 404 permits than it had previously undertaken. On October 6, 2011, the District Court for the District of Columbia rejected the ECP on several different legal grounds and later this same court enjoined EPA from any further usage of its final guidance. Any future application of procedures similar to ECP, such as may be enacted following notice and comment rulemaking, would have the potential to delay issuance of permits for surface coal mines, or to change the conditions or restrictions imposed in those permits.

The EPA also has statutory “veto” power under Section 404(c) to effectively revoke a previously issued Section 404 permit if the EPA determines, after notice and an opportunity for a public hearing, that the permit will have an “unacceptable adverse effect.” On January 14, 2011, the EPA exercised its Section 404(c) authority to withdraw or restrict the use of a previously issued permit for the Spruce No. 1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in Appalachia. This action was the first time that such power was exercised with regard to a previously permitted coal mining project. A challenge to the EPA’s exercise of this authority was made in the federal District Court in the District of Columbia and on March 23, 2012, the Court ruled that the EPA lacked the statutory authority to invalidate an already issued Section 404 permit retroactively. This decision was appealed and reversed by the D.C. Circuit Court of Appeals in April 2013, finding that EPA has the authority to issue a retroactive veto, but remanding for consideration of whether that decision was arbitrary and capricious. The mining company has also petitioned the U.S. Supreme Court for certiorari to overturn the ruling. The Supreme Court denied certiorari in March 2014. Any future use of the EPA’s Section 404 “veto” power could create uncertainty with regard to our or our lessees’ continued use of their current permits, as well as impose additional time and cost burdens on future operations, potentially adversely affecting our coal royalties revenues.

The Corps is authorized to issue general “nationwide” permits for specific categories of activities that are similar in nature and that are determined to have minimal adverse environmental effects. We may no longer seek general permits under Nationwide Permit 21, or NWP 21, because in February 2012, the Corps reinstated the use of NWP 21, but limited application of NWP 21 authorizations to discharges with impacts not greater than a half-acre of water, including no more than 300 linear feet of streambed, and disallowed the use of NWP 21 for valley fills. If the newly issued NWP 21 cannot be used for any of our proposed surface coal mining projects, we will have to obtain individual permits from the Corps subject to the additional EPA measures discussed below with the uncertainties and delays attendant to that process.

We currently have a number of Section 404 permit applications pending with the Corps. Not all of these permit applications seek approval for valley fills or other obvious “fills”; some relate to other activities, such as mining through streams and the associated post-mining reconstruction efforts. We sought to prepare all pending permit applications consistent with the requirements of the Section 404 program. Our five year plan of mining operations does not rely on the issuance of these pending permit applications. However, the Section 404 permitting requirements are complex, and regulatory scrutiny of these applications, particularly in Appalachia, has increased such that our applications may not be granted or, alternatively, the Corps may require material changes to our proposed operations before it grants permits. While we will continue to pursue the issuance of these permits in the ordinary course of our operations, to the extent that the permitting process creates significant delay or limits our ability to pursue certain reserves beyond our current five year plan, our revenues may be negatively affected.

Total Maximum Daily Load, or TMDL, regulations under the CWA establish a process to calculate the maximum amount of a pollutant that an impaired water body can receive and still meet state water quality standards, and to allocate pollutant loads among the point- and non-point pollutant sources discharging into that water body. Likewise, when water quality in a receiving stream is better than required, states are required to conduct an anti-degradation review before approving discharge permits. The adoption of new TMDLs and load allocations or any changes to anti-degradation policies for streams near our coal mines could limit our ability to obtain NPDES permits, require more costly water treatment, and adversely affect our coal production.

Moreover, in April 2014, EPA proposed changes to its definition of “waters of the United States.” Because the content of EPA’s final rule, if any, is unknown, we cannot assess the potential impact of the EPA’s proposal on our operations. However, any expansion to Clean Water Act jurisdiction could impose additional permitting obligations on our operations, which may adversely impact our coal production or results of operations.

In May 2014, EPA issued a new final rule pursuant to Section 316(b) of the CWA that affects the cooling water intake structures at power plants in order to reduce fish impingement and entrainment. The rule is expected to affect over 500 power plants. These requirements could increase our customers’ costs and cause them to reduce their demand for coal, which may materially impact our results or operations.

Hazardous Substances and Wastes

The federal Comprehensive Environmental Response, Compensation and Liability Act, or 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 liabilities 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 substances. We are not aware of any material liability associated with the release or disposal of hazardous substances from our past or present mine sites.

The federal Resource Conservation and Recovery Act, or 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 the EPA to require corrective action at sites where there is a release of hazardous wastes. In addition, each state has its own laws regarding the proper management and disposal of waste material. While these laws impose ongoing compliance obligations, such costs are not believed to have a material impact on our operations.

In June 2010, EPA released a proposed rule to regulate the disposal of certain coal combustion by-products, or CCB. The proposed rule sets forth two proposed avenues for the regulation of CCB under RCRA. The first option called for regulation of CCB under Subtitle C as a hazardous waste, which creates a comprehensive program of federally enforceable requirements for waste management and disposal. The second option called for regulation of CCB under Subtitle D as a solid waste, which gives EPA authority to set performance standards for solid waste management facilities and would be enforced primarily through state agencies and citizen suits. In December 2014, EPA finalized regulations that address the management of coal ash as a non-hazardous solid waste under Subtitle D. The rules impose engineering, structural and siting standards on surface impoundments and landfills that hold coal combustion wastes and mandate regular inspections. The rule also requires fugitive dust controls and imposes various monitoring, cleanup, and closure requirements. The rule leaves intact the Bevill exemption for beneficial uses of CCB, though it defers a final Bevill regulatory determination with respect to CCB that is disposed of in landfills or surface impoundments. The costs of complying with these new requirements may result in a material adverse effect on our business, financial condition or results of operations, and could potentially increase our customers’ operating costs, thereby reducing their ability to purchase coal as a result. In addition, contamination caused by the past disposal of CCB, including coal ash, can lead to material liability to our customers under RCRA or other federal or state laws and potentially reduce the demand for coal.

Endangered Species Act

The federal Endangered Species Act and counterpart state legislation protect species threatened with possible extinction. Protection of threatened and endangered species may have the effect of prohibiting or delaying us from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats. A number of species indigenous to our properties are protected under the Endangered Species Act. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect our ability to mine coal from our properties in accordance with current mining plans.

Use of Explosives

We use explosives in connection with our surface mining activities. The Federal Safe Explosives Act, or SEA, applies to all users of explosives. Knowing or willful violations of the SEA may result in fines, imprisonment, or both. In addition, violations of SEA may result in revocation of user permits and seizure or forfeiture of explosive materials.

The storage of explosives is also subject to regulatory requirements. For example, pursuant to a rule issued by the Department of Homeland Security in 2007, facilities in possession of chemicals of interest (including ammonium nitrate at certain threshold levels) are required to complete a screening review in order to help determine whether there is a high level of security risk, such that a security vulnerability assessment and a site security plan will be required. It is possible that our use of explosives in connection with blasting operations may subject us to the Department of Homeland Security’s new chemical facility security regulatory program.

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

In January 2015, OSM announced that it intends to pursue a rulemaking to address clouds of nitrogen oxide associated with blasting operations pursuant to a petition by a nongovernmental organization. We are unable to predict the impact, if any, of these actions by the OSM, although the actions potentially could result in additional delays and costs associated with our blasting operations.

Other Environmental and Mine Safety Laws

We are required to comply with numerous other federal, state and local environmental and mine safety laws and regulations in addition to those previously discussed. These additional laws include, for example, the Safe Drinking Water Act, the Toxic Substance Control Act and the Emergency Planning and Community Right-to-Know Act. The costs of compliance with these requirements is not expected to have a material adverse effect on our business, financial condition or results of operations.

Employees

To carry out our operations, our general partner and our subsidiaries, excluding our Rhino Eastern joint venture, employed 715 full-time employees as of December 31, 2014. None of the employees are subject to collective bargaining agreements. We believe that we have good relations with these employees and since our inception we have had no history of work stoppages or union organizing campaigns.

Subsequent Developments in Rhino’s Business

The following material events have occurred with respect to Rhino’s business since the filing of it Form 10-K for fiscal 2014:

Suspension of Dividend on Common Units

On October 19, 2015, the Partnership announced it had continued the suspension of the cash distribution for its common units, which was initially suspended for the quarter ended June 30, 2015. No distribution will be paid for common or subordinated units for the quarter ended September 30, 2015. The Partnership’s common units accrue arrearages every quarter when the distribution level is below the minimum level of $0.445 per unit, as outlined in the Partnership’s limited partnership agreement. The Partnership initially lowered its quarterly common unit distribution below the minimum level of $0.445 per unit with the quarter ended September 30, 2014. Thus, the Partnership’s distributions for each of the quarters ended September 30, 2014 through the current quarter ended September 30, 2015 were below the minimum level and the current amount of accumulated arrearages as of September 30, 2015 related to the common unit distribution is approximately $36.5 million.

Idling and Sale of Central Appalachian Operations

In June 2015, we announced that we were temporarily idling a majority of our Central Appalachia coal operations due to ongoing weakness in the coal markets. Demand for Central Appalachia steam coal has fallen to unprecedented levels as utilities choose low-priced natural gas for electricity generation and other coal-fired capacity is shuttered due to governmental regulations. Met coal prices remain at depressed levels due to persistent worldwide oversupply and weak demand from China. Future market conditions will determine the duration that our Central Appalachia operations remain idle.

In Central Appalachia, we have focused on potential divestitures of certain mining operations, while retaining the mineral ownership or mineral rights to these properties that could generate future royalty income streams. This strategy would reduce our operational risk, reclamation liabilities and bonding requirements, while converting these properties to royalty generating assets that would provide stable, long-term cash flows. At our other coal mining operations in Northern Appalachia, the Illinois Basin and the Western Bituminous region, our strategy is to secure profitable, long-term sales contracts and keep operating costs low to maximize cash flows. We continue to evaluate our other non-core assets for potential divestiture to potentially monetize these assets and further reduce our debt level.

On October 30, 2015, we executed a binding letter of intent with a third party for the purchase of our Deane mining complex, subject to normal closing conditions. Our Deane mining complex is located in eastern Kentucky and includes one underground mine that is currently idle. The infrastructure at the Deane mining complex consists of a preparation plant and a unit train loadout facility. The contemplated sale of the Deane complex would transfer the underground mine, related equipment, the preparation plant and loadout facility, while we would retain the mineral rights for the 39.3 million tons of proven and probable steam coal reserves at this complex. The contemplated transaction would also include a royalty agreement with the third party pursuant to which we would collect future royalties for coal mined and sold from the Deane complex. The contemplated sale of the Deane complex would also relieve us of significant reclamation liabilities and bonding requirements. We evaluated the appropriate held for sale accounting criteria to determine if the Deane mining complex should be classified as held for sale as of September 30, 2015. Based on this evaluation, we determined the Deane mining complex met the held for sale criteria at September 30, 2015 and, accordingly, the Deane mining complex asset group was written down to its estimated fair value of $2.0 million. Due to the determination that the Deane mining complex met the held for sale criteria, we recorded an impairment charge of approximately $2.3 million for the three and nine months ended September 30, 2015. As of September 30, 2015, we classified approximately $8.8 million of assets and approximately $6.8 million of liabilities as held for sale on our unaudited condensed consolidated statements of financial position.

Cana Woodford

In August 2015, we completed the sale of our oil and natural gas investment of approximately 1,900 net mineral acres in the Cana Woodford region of western Oklahoma. We received a total of approximately $5.7 million in proceeds from the sale of the Cana Woodford oil and natural gas mineral rights. In the second quarter of 2015, we evaluated the appropriate held for sale accounting criteria to determine if the Cana Woodford mineral rights should be classified as held for sale as of June 30, 2015. Based on this evaluation, we determined these mineral rights met the held for sale criteria at June 30, 2015 and, accordingly, these mineral rights were written down to their estimated fair value of $5.8 million. Due to the determination that the mineral rights met the held for sale criteria, we recorded an impairment charge of approximately $2.2 million for the Cana Woodford mineral rights during the second quarter of 2015.

Debt Classification

We evaluated our amended and restated senior secured credit facility at September 30, 2015 to determine whether this debt liability should be classified as a long-term or short-term liability on our unaudited condensed consolidated statements of financial position. In April 2015, we entered into a third amendment of our amended and restated senior secured credit facility. The third amendment extended the expiration date of the amended and restated credit agreement to July 2017. The extension is contingent upon (i) our leverage ratio being less than or equal to 2.75 to 1.0 and (ii) our having liquidity greater than or equal to $15 million, in each case for either the quarter ending December 31, 2015 or March 31, 2016. If both of these conditions are not satisfied for one of such quarters, the expiration date of the amended and restated credit agreement will revert to July 2016. As of September 30, 2015, our leverage ratio was 3.2 to 1.0 and our liquidity was approximately $9.0 million. Based on current projections, our current normal operating forecast indicates that we will not meet both of these extension conditions for either quarter. Based on this analysis, we determined that our credit facility debt liability of $48.0 million at September 30, 2015 should be classified as a current liability on our unaudited condensed consolidated statements of financial position. The classification of our credit facility balance as a current liability raises substantial doubt of our ability to continue as a going concern for the next twelve months. We are currently analyzing multiple options to meet the credit facility contingent extension conditions, which includes potential sales of non-core assets. We are also considering alternative financing options that could result in a new long-term credit facility with a potential five-year term. However, we may be unable to complete such transactions on terms acceptable to us or at all. If we are unable to meet the extension conditions on our credit facility and the expiration date of the credit agreement reverts to July 2016, we will have to secure alternative financing to replace our credit facility by the expiration date of July 2016 in order to continue our normal business operations. For more information about our credit facility and the third amendment, please read “—Liquidity and Capital Resources—Amended and Restated Credit Agreement.”

Delisting of Common Units from NYSE

On December 17, 2015, the Partnership was notified by the New York Stock Exchange (the “NYSE”) that the NYSE has determined to commence proceedings to delist its common units representing limited partner interests of the Partnership (the “Common Units”) from the NYSE as a result of the Partnership’s failure to comply with the continued listing standard set forth in Section 802.01B of the NYSE Listed Company Manual to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15 million for its Common Units. The NYSE also suspended the trading of the Common Units at the close of trading on December 17, 2015.

On December 11, 2015, the Partnership notified the NYSE of its intention to voluntarily transfer its Common Units from the NYSE to the OTCQB Marketplace (“OTCQB”). However, the NYSE’s proceedings to delist the Common Units superseded the Partnership’s voluntary transfer. The Common Units began trading on the OTCQB on December 18, 2015. The Partnership remains subject to the public reporting requirements of the Securities and Exchange Commission following the transfer to the OTCQB.

EXHIBIT B

Risk Factors of Rhino Resource Partners, LP

We may not have sufficient cash to enable us to pay the minimum quarterly distribution on our common units following establishment of cash reserves and payment of costs and expenses, including reimbursement of expenses to our general partner.

We may not have sufficient cash each quarter to pay the full amount of our minimum quarterly distribution of $0.445 per unit, or $1.78 per unit per year, which will require us to have available cash of approximately $13.2 million per quarter, or $52.8 million per year, based on the number of common and subordinated units outstanding as of December 31, 2013 and the general partner interest. The amount of cash we can distribute on our common and subordinated units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

	●	the amount of coal we are able to produce from our properties, which could be adversely affected by, among other things, operating difficulties and unfavorable geologic conditions;

	●	the price at which we are able to sell coal, which is affected by the supply of and demand for domestic and foreign coal;

	●	the level of our operating costs, including reimbursement of expenses to our general partner and its affiliates. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed;

	●	the proximity to and capacity of transportation facilities;

	●	the price and availability of alternative fuels;

	●	the impact of future environmental and climate change regulations, including those impacting coal-fired power plants;

	●	the level of worldwide energy and steel consumption;

	●	prevailing economic and market conditions;

	●	difficulties in collecting our receivables because of credit or financial problems of customers;

	●	the effects of new or expanded health and safety regulations;

	●	domestic and foreign governmental regulation, including changes in governmental regulation of the mining industry, the electric utility industry or the steel industry;

	●	changes in tax laws;

	●	weather conditions; and

	●	force majeure.

In addition, we have not paid any distributions on our subordinated units for any quarter after the quarter ended March 31, 2012. We may not have sufficient cash available for distributions on our subordinated units in the future. Any further reduction in the amount of cash available for distributions could impact our ability to pay the minimum quarterly distribution on our common units in full. Moreover, we may not be able to increase distributions on our common units if we are unable to pay the full minimum quarterly distribution on our subordinated units.

A decline in coal prices could adversely affect our results of operations and cash available for distribution to our unitholders.

Our results of operations and the value of our coal reserves are significantly dependent upon the prices we receive for our coal as well as our ability to improve productivity and control costs. The prices we receive for coal depend upon factors beyond our control, including:

	●	the supply of domestic and foreign coal;

	●	the demand for domestic and foreign coal, which is significantly affected by the level of consumption of steam coal by electric utilities and the level of consumption of metallurgical coal by steel producers;

	●	the proximity to, and capacity of, transportation facilities;

	●	domestic and foreign governmental regulations, particularly those relating to the environment, climate change, health and safety;

	●	the level of domestic and foreign taxes;

	●	the price and availability of alternative fuels for electricity generation;

	●	weather conditions;

	●	terrorist attacks and the global and domestic repercussions from terrorist activities; and

	●	prevailing economic conditions.

Any adverse change in these factors could result in weaker demand and lower prices for our products. In addition, the recent global economic downturn, coupled with the global financial and credit market disruptions, has had an impact on the coal industry generally and may continue to do so. The demand for electricity and steel may remain at low levels or further decline if economic conditions remain weak. If these trends continue, we may not be able to sell all of the coal we are capable of producing or sell our coal at prices comparable to recent years. Recent low prices for natural gas, which is a substitute for coal generated power, may also lead to continued decreased coal consumption by electricity-generating utilities. A substantial or extended decline in the prices we receive for our coal supply contracts could materially and adversely affect our results of operations.

We could be negatively impacted by the competitiveness of the global markets in which we compete and declines in the market demand for coal.

We compete with coal producers in various regions of the United States and overseas for domestic and international sales. The domestic demand for, and prices of, our coal primarily depend on coal consumption patterns of the domestic electric utility industry and the domestic steel industry. Consumption by the domestic electric utility industry is affected by the demand for electricity, environmental and other governmental regulations, technological developments and the price of competing coal and alternative fuel sources, such as natural gas, nuclear, hydroelectric and wind power and other renewable energy sources. Consumption by the domestic steel industry is primarily affected by economic growth and the demand for steel used in construction as well as appliances and automobiles. The competitive environment for coal is impacted by a number of the largest markets in the world, including the United States, China, Japan and India, where demand for both electricity and steel has supported prices for steam and metallurgical coal. The economic stability of these markets has a significant effect on the demand for coal and the level of competition in supplying these markets. The cost of ocean transportation and the value of the U.S. dollar in relation to foreign currencies significantly impact the relative attractiveness of our coal as we compete on price with foreign coal producing sources. During the last several years, the U.S. coal industry has experienced increased consolidation, which has contributed to the industry becoming more competitive. Increased competition by coal producers or producers of alternate fuels could decrease the demand for, or pricing of, or both, for our coal, adversely impacting our results of operations and cash available for distribution.

Portions of our coal reserves possess quality characteristics that enable us to mine, process and market them as either metallurgical coal or high quality steam coal, depending on prevailing market conditions. A decline in the metallurgical market relative to the steam market could cause us to shift coal from the metallurgical market to the steam market, potentially reducing the price we could obtain for this coal and adversely impacting our cash flows, results of operations and cash available for distribution.

Any change in consumption patterns by utilities away from the use of coal, such as resulting from current low natural gas prices, could affect our ability to sell the coal we produce, which could adversely affect our results of operations and cash available for distribution to our unitholders.

Excluding results from the Rhino Eastern joint venture, steam coal accounted for approximately 84% of our coal sales volume for the year ended December 31, 2013. The majority of our sales of steam coal during this period were to electric utilities for use primarily as fuel for domestic electricity consumption. The amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas and oil as well as alternative sources of energy. We compete generally with producers of other fuels, such as natural gas and oil. A decline in price for these fuels could cause demand for coal to decrease and adversely affect the price of our coal. For example, low natural gas prices have led, in some instances, to decreased coal consumption by electricity-generating utilities. If alternative energy sources, such as nuclear, hydroelectric, wind or solar, become more cost-competitive on an overall basis, demand for coal could decrease and the price of coal could be materially and adversely affected. Further, legislation requiring, subsidizing or providing tax benefit for the use of alternative energy sources and fuels, or legislation providing financing or incentives to encourage continuing technological advances in this area, could further enable alternative energy sources to become more competitive with coal. A decrease in coal consumption by the domestic electric utility industry could adversely affect the price of coal, which could materially adversely affect our results of operations and cash available for distribution to our unitholders.

Our mining operations are subject to extensive and costly environmental laws and regulations, and such current and future laws and regulations could materially increase our operating costs or limit our ability to produce and sell coal.

The coal mining industry is subject to numerous and extensive federal, state and local environmental laws and regulations, including laws and regulations pertaining to permitting and licensing requirements, air quality standards, plant and wildlife protection, reclamation and restoration of mining properties, the discharge of materials into the environment, the storage, treatment and disposal of wastes, protection of wetlands, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. The costs, liabilities and requirements associated with these laws and regulations are significant and time-consuming and may delay commencement or continuation of our operations. Moreover, the possibility exists that new laws or regulations (or new judicial interpretations or enforcement policies of existing laws and regulations) could materially affect our mining operations, results of operations and cash available for distribution to our unitholders, either through direct impacts such as those regulating our existing mining operations, or indirect impacts such as those that discourage or limit our customers’ use of coal. Although we believe that we are in substantial compliance with existing laws and regulations, we may, in the future, experience violations that would subject us to administrative, civil and criminal penalties and a range of other possible sanctions. The enforcement of laws and regulations governing the coal mining industry has increased substantially. As a result, the consequences for any noncompliance may become more significant in the future.

Our operations use petroleum products, coal processing chemicals and other materials that may be considered “hazardous materials” under applicable environmental laws and have the potential to generate other materials, all of which may affect runoff or drainage water. In the event of environmental contamination or a release of these materials, we could become subject to claims for toxic torts, natural resource damages and other damages and for the investigation and cleanup of soil, surface water, groundwater, and other media, as well as abandoned and closed mines located on property we operate. Such claims may arise out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire.

The government extensively regulates mining operations, especially with respect to mine safety and health, which imposes significant actual and potential costs on us, and future regulation could increase those costs or limit our ability to produce coal.

Coal mining is subject to inherent risks to safety and health. As a result, the coal mining industry is subject to stringent safety and health standards. Fatal mining accidents in the United States in recent years have received national attention and have led to responses at the state and federal levels that have resulted in increased regulatory scrutiny of coal mining operations, particularly underground mining operations. More stringent state and federal mine safety laws and regulations have included increased sanctions for non-compliance. Moreover, future workplace accidents are likely to result in more stringent enforcement and possibly the passage of new laws and regulations.

Within the last few years, the industry has seen enactment of the Federal Mine Improvement and New Emergency Response Act of 2006 (the “MINER Act”), subsequent additional legislation and regulation imposing significant new safety initiatives and the Dodd-Frank Act, which, among other things, imposes new mine safety information reporting requirements. The MINER Act significantly amended the Federal Mine Safety and Health Act of 1977, or the Mine Act, imposing more extensive and stringent compliance standards, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection, and enforcement activities. Following the passage of the MINER Act, the U.S. Mine Safety and Health Administration (“MSHA”) issued new or more stringent rules and policies on a variety of topics, including:

	●	sealing off abandoned areas of underground coal mines;

	●	mine safety equipment, training and emergency reporting requirements;

	●	substantially increased civil penalties for regulatory violations;

	●	training and availability of mine rescue teams;

	●	underground “refuge alternatives” capable of sustaining trapped miners in the event of an emergency;

	●	flame-resistant conveyor belt, fire prevention and detection, and use of air from the belt entry; and

	●	post-accident two-way communications and electronic tracking systems.

Subsequent to passage of the MINER Act, various coal producing states, including West Virginia, Ohio and Kentucky, have enacted legislation addressing issues such as mine safety and accident reporting, increased civil and criminal penalties, and increased inspections and oversight. Other states may pass similar legislation in the future. Additional federal and state legislation that would further increase mine safety regulation, inspection and enforcement, particularly with respect to underground mining operations, has also been considered.

MSHA is also considering a new rule regarding respirable coal mine dust that, if promulgated, would lower the allowable average concentration of respirable dust, allow for single shift sampling to determine noncompliance and establish regulations for the use of Continuous Personal Dust Monitors, among other things. This proposed rule is in the final rule stage and could require significant expenditures in order to comply.

Although we are unable to quantify the full impact, implementing and complying with these new laws and regulations could have an adverse impact on our results of operations and cash available for distribution to our unitholders and could result in harsher sanctions in the event of any violations. Please read “Item 1. Business—Regulation and Laws.”

Penalties, fines or sanctions levied by MSHA could have a material adverse effect on our business, results of operations and cash available for distribution.

Surface and underground mines like ours are continuously inspected by MSHA, which often leads to notices of violation. Recently, MSHA has been conducting more frequent and more comprehensive inspections.

On June 24, 2011, our subsidiary, CAM Mining LLC received notice that on June 23, 2011, MSHA commenced an action in the U.S. District Court of the Eastern District of Kentucky seeking injunctive relief as a result of alleged violations of Sections 103, 104, and 108 of the Mine Act occurring at Mine 28 in connection with an inspection on June 17, 2011 by MSHA inspectors. The complaint alleged that when MSHA inspectors arrived at Mine 28 to inspect the mine with respect to the allegations that employees had been smoking underground, CAM Mining LLC employees gave advance notice of the inspection to miners working underground and that this advance notice hindered, interfered with and delayed the inspection by MSHA. The complaint asserts that the MSHA inspectors did not find any evidence of smoking paraphernalia during the inspection, which was allegedly the result of this advance notice. On June 30, 2011, MSHA obtained a temporary restraining order prohibiting any advance notice of inspections in the future. That became a Permanent Injunction on July 14, 2011. The Permanent Injunction is for three years and will expire on July 14, 2014. On June 17, 2011, MSHA also issued a 104(a) citation in this matter to the Mine for allegedly giving advance notice of the inspection. The citation was assessed at $10,000 and is expected to be settled at $8,000 upon approval by the administrative law judge in 2014.

As a result of these and future inspections and alleged violations and potential violations, we could be subject to material fines, penalties or sanctions. Any of our mines could be subject to a temporary or extended shut down as a result of an alleged MSHA violation. Any such penalties, fines or sanctions could have a material adverse effect on our business, results of operations and cash available for distribution.

We may be unable to obtain and/or renew permits necessary for our operations, which could prevent us from mining certain reserves.

Numerous governmental permits and approvals are required for mining operations, and we can face delays, challenges to, and difficulties in acquiring, maintaining or renewing necessary permits and approvals, including environmental permits. The permitting rules, and the interpretations of these rules, are complex, change frequently, and are often subject to discretionary interpretations by regulators, all of which may make compliance more difficult or impractical, and may possibly preclude the continuance of ongoing mining operations or the development of future mining operations. In addition, the public has certain statutory rights to comment upon and otherwise impact the permitting process, including through court intervention. Over the past few years, the length of time needed to bring a new surface mine into production has increased because of the increased time required to obtain necessary permits. The slowing pace at which permits are issued or renewed for new and existing mines has materially impacted production in Appalachia, but could also affect other regions in the future.

Section 402 National Pollutant Discharge Elimination System permits and Section 404 CWA permits are required to discharge wastewater and discharge dredged or fill material into waters of the United States. Our surface coal mining operations typically require such permits to authorize such activities as the creation of slurry ponds, stream impoundments, and valley fills. Although the CWA gives the EPA a limited oversight role in the Section 404 permitting program, the EPA has recently asserted its authorities more forcefully to question, delay, and prevent issuance of some Section 404 permits for surface coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits.

Please read “Part I, Item 1. Business—Regulation and Laws—Clean Water Act” for a discussion of recent litigation and regulatory developments related to the CWA. An inability to obtain the necessary permits to conduct our mining operations or an inability to comply with the requirements of applicable permits would reduce our production and cash flows, which could limit our ability to make distributions to our unitholders.

Our mining operations are subject to operating risks that could adversely affect production levels and operating costs.

Our mining operations are subject to conditions and events beyond our control that could disrupt operations, resulting in decreased production levels and increased costs.

These risks include:

	●	unfavorable geologic conditions, such as the thickness of the coal deposits and the amount of rock embedded in or overlying the coal deposit;

	●	inability to acquire or maintain necessary permits or mining or surface rights;

	●	changes in governmental regulation of the mining industry or the electric utility industry;

	●	adverse weather conditions and natural disasters;

	●	accidental mine water flooding;

	●	labor-related interruptions;

	●	transportation delays;

	●	mining and processing equipment unavailability and failures and unexpected maintenance problems; and

	●	accidents, including fire and explosions from methane.

Any of these conditions may increase the cost of mining and delay or halt production at particular mines for varying lengths of time, which in turn could adversely affect our results of operations and cash available for distribution to our unitholders.

In general, mining accidents present a risk of various potential liabilities depending on the nature of the accident, the location, the proximity of employees or other persons to the accident scene and a range of other factors. Possible liabilities arising from a mining accident include workmen’s compensation claims or civil lawsuits for workplace injuries, claims for personal injury or property damage by people living or working nearby and fines and penalties including possible criminal enforcement against us and certain of our employees. In addition, a significant accident that results in a mine shut-down could give rise to liabilities for failure to meet the requirements of coal supply agreements especially if the counterparties dispute our invocation of the force majeure provisions of those agreements. We maintain insurance coverage to mitigate the risks of certain of these liabilities, including business interruption insurance, but those policies are subject to various exclusions and limitations and we cannot assure you that we will receive coverage under those policies for any personal injury, property damage or business interruption claims that may arise out of such an accident. Moreover, certain potential liabilities such as fines and penalties are not insurable risks. Thus, a serious mine accident may result in material liabilities that adversely affect our results of operations and cash available for distribution.

Fluctuations in transportation costs or disruptions in transportation services could increase competition or impair our ability to supply coal to our customers, which could adversely affect our results of operations and cash available for distribution to our unitholders.

Transportation costs represent a significant portion of the total cost of coal for our customers and, as a result, the cost of transportation is a critical factor in a customer’s purchasing decision. Increases in transportation costs could make coal a less competitive energy source or could make our coal production less competitive than coal produced from other sources.

Significant decreases in transportation costs could result in increased competition from coal producers in other regions. For instance, coordination of the many eastern U.S. coal loading facilities, the large number of small shipments, the steeper average grades of the terrain and a more unionized workforce are all issues that combine to make shipments originating in the eastern United States inherently more expensive on a per-mile basis than shipments originating in the western United States. Historically, high coal transportation rates from the western coal producing regions limited the use of western coal in certain eastern markets. The increased competition could have an adverse effect on our results of operations and cash available for distribution to our unitholders.

We depend primarily upon railroads, barges and trucks to deliver coal to our customers. Disruption of any of these services due to weather-related problems, strikes, lockouts, accidents, mechanical difficulties and other events could temporarily impair our ability to supply coal to our customers, which could adversely affect our results of operations and cash available for distribution to our unitholders.

In recent years, the states of Kentucky and West Virginia have increased enforcement of weight limits on coal trucks on their public roads. It is possible that other states may modify their laws to limit truck weight limits. Such legislation and enforcement efforts could result in shipment delays and increased costs. An increase in transportation costs could have an adverse effect on our ability to increase or to maintain production and could adversely affect our results of operations and cash available for distribution.

A shortage of skilled labor in the mining industry could reduce productivity and increase operating costs, which could adversely affect our results of operations and cash available for distribution to our unitholders.

Efficient coal mining using modern techniques and equipment requires skilled laborers. During periods of high demand for coal, the coal industry has experienced a shortage of skilled labor as well as rising labor and benefit costs, due in large part to demographic changes as existing miners retire at a faster rate than new miners are entering the workforce. If a shortage of experienced labor should occur or coal producers are unable to train enough skilled laborers, there could be an adverse impact on labor productivity, an increase in our costs and our ability to expand production may be limited. If coal prices decrease or our labor prices increase, our results of operations and cash available for distribution to our unitholders could be adversely affected.

Unexpected increases in raw material costs, such as steel, diesel fuel and explosives could adversely affect our results of operations.

Our coal mining operations are affected by commodity prices. We use significant amounts of steel, diesel fuel, explosives and other raw materials in our mining operations, and volatility in the prices for these raw materials could have a material adverse effect on our operations. Steel prices and the prices of scrap steel, natural gas and coking coal consumed in the production of iron and steel fluctuate significantly and may change unexpectedly. Additionally, a limited number of suppliers exist for explosives, and any of these suppliers may divert their products to other industries. Shortages in raw materials used in the manufacturing of explosives, which, in some cases, do not have ready substitutes, or the cancellation of supply contracts under which these raw materials are obtained, could increase the prices and limit the ability of us or our contractors to obtain these supplies. Future volatility in the price of steel, diesel fuel, explosives or other raw materials will impact our operating expenses and could adversely affect our results of operations and cash available for distribution.

If we are not able to acquire replacement coal reserves that are economically recoverable, our results of operations and cash available for distribution to our unitholders could be adversely affected.

Our results of operations and cash available for distribution to our unitholders depend substantially on obtaining coal reserves that have geological characteristics that enable them to be mined at competitive costs and to meet the coal quality needed by our customers. Because we deplete our reserves as we mine coal, our future success and growth will depend, in part, upon our ability to acquire additional coal reserves that are economically recoverable. If we fail to acquire or develop additional reserves, our existing reserves will eventually be depleted. Replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. We may not be able to accurately assess the geological characteristics of any reserves that we acquire, which may adversely affect our results of operations and cash available for distribution to our unitholders. Exhaustion of reserves at particular mines with certain valuable coal characteristics also may have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by such mines. Our ability to obtain other reserves in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates or the inability to acquire coal properties on commercially reasonable terms.

Inaccuracies in our estimates of coal reserves and non-reserve coal deposits could result in lower than expected revenues and higher than expected costs.

We base our and the Rhino Eastern joint venture’s coal reserve and non-reserve coal deposit estimates on engineering, economic and geological data assembled and analyzed by our staff, which is periodically audited by independent engineering firms. These estimates are also based on the expected cost of production and projected sale prices and assumptions concerning the permitability and advances in mining technology. The estimates of coal reserves and non-reserve coal deposits as to both quantity and quality are periodically updated to reflect the production of coal from the reserves, updated geologic models and mining recovery data, recently acquired coal reserves and estimated costs of production and sales prices. There are numerous factors and assumptions inherent in estimating quantities and qualities of coal reserves and non-reserve coal deposits and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves necessarily depend upon a number of variable factors and assumptions, all of which may vary considerably from actual results. These factors and assumptions relate to:

	●	quality of coal;

	●	geological and mining conditions and/or effects from prior mining that may not be fully identified by available exploration data or which may differ from our experience in areas where we currently mine;

	●	the percentage of coal in the ground ultimately recoverable;

	●	the assumed effects of regulation, including the issuance of required permits, taxes, including severance and excise taxes and royalties, and other payments to governmental agencies;

	●	historical production from the area compared with production from other similar producing areas;

	●	the timing for the development of reserves; and

	●	assumptions concerning equipment and productivity, future coal prices, operating costs, capital expenditures and development and reclamation costs.

For these reasons, estimates of the quantities and qualities of the economically recoverable coal attributable to any particular group of properties, classifications of coal reserves and non-reserve coal deposits based on risk of recovery, estimated cost of production and estimates of net cash flows expected from particular reserves as prepared by different engineers or by the same engineers at different times may vary materially due to changes in the above factors and assumptions. Actual production from identified coal reserve and non-reserve coal deposit areas or properties and revenues and expenditures associated with our and Rhino Eastern’s mining operations may vary materially from estimates. Accordingly, these estimates may not reflect our and Rhino Eastern’s actual coal reserves or non-reserve coal deposits. Any inaccuracy in our estimates related to our and Rhino Eastern’s coal reserves and non-reserve coal deposits could result in lower than expected revenues and higher than expected costs, which could have a material adverse effect on our ability to make cash distributions.

We invest in non-coal natural resource assets, which could result in a material adverse effect on our results of operations and cash available for distribution to our unitholders.

Part of our business strategy is to expand our operations through strategic acquisitions, which includes investing in non-coal natural resources assets. Our executive officers do not have experience investing in or operating non-coal natural resources assets and we may be unable to hire additional management with relevant expertise in operating such assets. Acquisitions of non-coal natural resource assets could expose us to new and additional operating and regulatory risks, including commodity price risk, which could result in a material adverse effect on our results of operations and cash available for distribution to our unitholders.

In addition, the natural gas industry could be impacted by the controversy surrounding hydraulic fracturing to extract shale gas. This could include additional regulations imposed on the industry.

We are not the operator of our oil and natural gas properties and therefore are not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties.

We are not the operator of the oil and natural gas properties in which we hold interests and may have limited ability to exercise influence over the operations of these and our other non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs, could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploration activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:

	●	The timing and amount of capital expenditures;

	●	The availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;

	●	The operator’s expertise and financial resources;

	●	Approval of other participants in drilling wells;

	●	Selection of technology; and

	●	The rate of production of the reserves.

In addition, when we are not the majority owner or operator of a particular oil or natural gas project, if we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited.

The amount of estimated maintenance capital expenditures our general partner is required to deduct from operating surplus each quarter could increase in the future, resulting in a decrease in available cash from operating surplus that could be distributed to our unitholders.

Our partnership agreement requires our general partner to deduct from operating surplus each quarter estimated maintenance capital expenditures as opposed to actual maintenance capital expenditures in order to reduce disparities in operating surplus caused by fluctuating maintenance capital expenditures, such as reserve replacement costs or refurbishment or replacement of mine equipment. Our annual estimated maintenance capital expenditures for purposes of calculating operating surplus are $7 to $10 million for 2014. This amount is based on our current estimates of the amounts of expenditures we will be required to make in the future to maintain our long-term operating capacity, which we believe to be reasonable. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. The amount of our estimated maintenance capital expenditures may be more than our actual maintenance capital expenditures, which will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution to unitholders. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of directors of our general partner at least once a year, with any change approved by the conflicts committee. In addition to estimated maintenance capital expenditures, reimbursement of expenses incurred by our general partner and its affiliates will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution to our unitholders. Please read “—Risks Inherent in an Investment in Us—Cost reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our unitholders. The amount and timing of such reimbursements will be determined by our general partner.”

Existing and future laws and regulations regulating the emission of sulfur dioxide and other compounds could affect coal consumers and as a result reduce the demand for our coal. A reduction in demand for our coal could adversely affect our results of operations and cash available for distribution to our unitholders.

Federal, state and local laws and regulations extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from electric power plants and other consumers of our coal. These laws and regulations can require significant emission control expenditures, and various new and proposed laws and regulations may require further emission reductions and associated emission control expenditures. A certain portion of our coal has a medium to high sulfur content, which results in increased sulfur dioxide emissions when combusted and therefore the use of our coal imposes certain additional costs on customers. Accordingly, these laws and regulations may affect demand and prices for our higher sulfur coal. Please read “Part I, Item 1. Business—Regulation and Laws.”

Federal and state laws restricting the emissions of greenhouse gases in areas where we conduct our business or sell our coal could adversely affect our operations and demand for our coal.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere and impacting climate. In response to such studies, the U.S. Congress is considering legislation to reduce emissions of GHG. Many states have already taken legal measures to reduce emissions of GHG, primarily through the development of regional GHG cap-and-trade programs.

In the wake of the Supreme Court’s April 2, 2007 decision in Massachusetts, et al. v. EPA, which held that GHG fall under the definition of “air pollutant” in the federal Clean Air Act (“CAA”) in December 2009 the EPA issued a final rule declaring that six GHG, including carbon dioxide and methane, “endanger both the public health and the public welfare of current and future generations.” The issuance of this “endangerment finding” allows the EPA to begin regulating GHG emissions under existing provisions of the CAA. There are many regulatory approaches currently in effect or being considered to address GHG, including possible future U.S. treaty commitments, new state legislation that may impose a carbon emissions tax or establish a cap-and-trade program and regulation by the EPA.

The permitting of new coal-fired power plants has also been contested by state regulators and environmental organizations for concerns related to GHG emissions from the new plants. In addition, several permits issued to new coal-fired power plants without limits on GHG emissions have been appealed to EPA’s Environmental Appeals Board. As state permitting authorities continue to consider GHG control requirements as part of major source permitting Best Available Control Technology (“BACT”) requirements, costs associated with new facility permitting and use of coal could increase substantially. A growing concern is the possibility that BACT will be determined to be the use of an alternative fuel to coal.

As a result of these current and proposed laws, regulations and trends, electricity generators may elect to switch to other fuels that generate less GHG emissions, possibly further reducing demand for our coal, which could adversely affect our results of operations and cash available for distribution to our unitholders. Please read “Part I, Item 1. Business—Regulation and Laws—Carbon Dioxide Emissions.”

Federal and state laws require bonds to secure our obligations to reclaim mined property. Our inability to acquire or failure to maintain, obtain or renew these surety bonds could have an adverse effect on our ability to produce coal, which could adversely affect our results of operations and cash available for distribution to our unitholders.

We are required under federal and state laws to place and maintain bonds to secure our obligations to repair and return property to its approximate original state after it has been mined (often referred to as “reclamation”) and to satisfy other miscellaneous obligations. Federal and state governments could increase bonding requirements in the future. Certain business transactions, such as coal leases and other obligations, may also require bonding. We may have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees, additional collateral, including supporting letters of credit or posting cash collateral or other terms less favorable to us upon those renewals. The failure to maintain or the inability by state and federal laws, could subject us to fines and penalties as well as the loss of our mining permits. Such failure could result from a variety of factors, including:

	●	the lack of availability, higher expense or unreasonable terms of new surety bonds;

	●	the ability of current and future surety bond issuers to increase required collateral; and

	●	the exercise by third-party surety bond holders of their right to refuse to renew the surety bonds.

We maintain surety bonds with third parties for reclamation expenses and other miscellaneous obligations. It is possible that we may in the future have difficulty maintaining our surety bonds for mine reclamation. Due to adverse economic conditions and the volatility of the financial markets, surety bond providers may be less willing to provide us with surety bonds or maintain existing surety bonds or may demand terms that are less favorable to us than the terms we currently receive. We may have greater difficulty satisfying the liquidity requirements under our existing surety bond contracts. As of December 31, 2013, we had $75.2 million in reclamation surety bonds, secured by $17.2 million in letters of credit outstanding under our credit agreement. Our credit agreement provides for a $300 million working capital revolving credit facility, of which up to $75.0 million may be used for letters of credit. If we do not maintain sufficient borrowing capacity under our revolving credit facility for additional letters of credit, we may be unable to obtain or renew surety bonds required for our mining operations. For more information, please read “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement.” If we do not maintain sufficient borrowing capacity or have other resources to satisfy our surety and bonding requirements, our operations and cash available for distribution to our unitholders could be adversely affected.

We depend on a few customers for a significant portion of our revenues. If a substantial portion of our supply contracts terminate or if any of these customers were to significantly reduce their purchases of coal from us, and we are unable to successfully renegotiate or replace these contracts on comparable terms, then our results of operations and cash available for distribution to our unitholders could be adversely affected.

We sell a material portion of our coal under supply contracts. As of December 31, 2013 we had sales commitments for approximately 80% of our estimated coal production (including purchased coal to supplement our production and excluding results from the Rhino Eastern joint venture) for the year ending December 31, 2014. When our current contracts with customers expire, our customers may decide not to extend or enter into new contracts. Of our total future committed tons, under the terms of the supply contracts, we will ship 43% in 2014, 25% in 2015, 16% in 2016, and 16% in 2017. We derived approximately 86.6% of our total revenues from coal sales (excluding results from the joint venture) to our ten largest customers for the year ended December 31, 2013, with affiliates of our top three customers accounting for approximately 45.9% of our coal revenues during that period.

In the absence of long-term contracts, our customers may decide to purchase fewer tons of coal than in the past or on different terms, including different pricing terms. Negotiations to extend existing contracts or enter into new long-term contracts with those and other customers may not be successful, and those customers may not continue to purchase coal from us under long-term coal supply contracts or may significantly reduce their purchases of coal from us. In addition, interruption in the purchases by or operations of our principal customers could significantly affect our results of operations and cash available for distribution. Unscheduled maintenance outages at our customers’ power plants and unseasonably moderate weather are examples of conditions that might cause our customers to reduce their purchases. Our mines may have difficulty identifying alternative purchasers of their coal if their existing customers suspend or terminate their purchases. The amount and terms of sales of coal produced from our Rhino Eastern mining complex are controlled by an affiliate of Patriot pursuant to the joint venture agreement. We cannot guarantee that Patriot will be successful in obtaining coal supply contracts at favorable prices, if at all, which could have a material adverse effect on our results of operations and cash available for distribution to our unitholders. For additional information relating to these contracts, please read “Part I, Item 1. Business—Customers—Coal Supply Contracts.”

Certain provisions in our long-term coal supply contracts may provide limited protection during adverse economic conditions, may result in economic penalties to us or permit the customer to terminate the contract.

Price adjustment, “price re-opener” and other similar provisions in our supply contracts may reduce the protection from short-term coal price volatility traditionally provided by such contracts. Price re-opener provisions typically require the parties to agree on a new price. Failure of the parties to agree on a price under a price re-opener provision can lead to termination of the contract. Any adjustment or renegotiations leading to a significantly lower contract price could adversely affect our results of operations and cash available for distribution to our unitholders.

Coal supply contracts also typically contain force majeure provisions allowing temporary suspension of performance by us or our customers during the duration of specified events beyond the control of the affected party. Most of our coal supply contracts also contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, hardness and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. In addition, certain of our coal supply contracts permit the customer to terminate the agreement in the event of changes in regulations affecting our industry that increase the price of coal beyond a specified limit.

Our coal lessees’ mining operations and their financial condition and results of operations are subject to some of the same risks and uncertainties that we face as a mine operator.

The mining operations and financial condition and results of operations of our coal lessees are subject to the same risks and uncertainties that we face as a mine operator. If any such risks were to occur, the business, financial condition and results of operations of the lessees could be adversely affected and as a result our coal royalty revenues and cash available for distribution could be adversely affected.

If our coal lessees do not manage their operations well, their production volumes and our royalty revenues could decrease.

We depend on our coal lessees to effectively manage their operations on the leased properties. The lessees make their own business decisions with respect to their operations within the constraints of their leases, including decisions relating to:

	●	marketing of the coal mined;

	●	mine plans, including the amount to be mined and the method of mining;

	●	processing and blending coal;

	●	expansion plans and capital expenditures;

	●	credit risk of their customers;

	●	permitting;

	●	insurance and surety bonding;

	●	acquisition of surface rights and other coal estates;

	●	employee wages;

	●	transportation arrangements;

	●	compliance with applicable laws, including environmental laws; and

	●	mine closure and reclamation.

A failure on the part of one of the coal lessees to make royalty payments could give us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we might not be able to find a replacement lessee or enter into a new lease on favorable terms within a reasonable period of time. In addition, the existing lessee could be subject to bankruptcy proceedings that could further delay the execution of a new lease or the assignment of the existing lease to another operator. If we enter into a new lease, the replacement operator might not achieve the same levels of production or sell coal at the same price as the lessee it replaced. In addition, it may be difficult to secure new or replacement lessees for small or isolated coal reserves, since industry trends toward consolidation favor larger-scale, higher-technology mining operations in order to increase productivity.

Coal lessees could satisfy obligations to their customers with coal from properties other than ours, depriving us of the ability to receive amounts in excess of minimum royalty payments.

Coal supply contracts often require operators to satisfy their obligations to their customers with resources mined from specific reserves or may provide the operator flexibility to source the coal from various reserves. Several factors may influence a coal lessee’s decision to supply its customers with coal mined from properties we do not own or lease, including the royalty rates under the coal lessee’s lease with us, mining conditions, mine operating costs, cost and availability of transportation, and customer specifications. If a coal lessee satisfies its obligations to its customers with coal from properties we do not own or lease, production on our properties will decrease, and we will receive lower royalty revenues.

A coal lessee may incorrectly report royalty revenues, which might not be identified by our lessee audit process or our mine inspection process or, if identified, might be identified in a subsequent period.

We depend on our lessees to correctly report production and royalty revenues on a monthly basis. Our regular lessee audits and mine inspections may not discover any irregularities in these reports or, if we do discover errors, we might not identify them in the reporting period in which they occurred. Any undiscovered reporting errors could result in a loss of royalty revenues and errors identified in subsequent periods could lead to accounting disputes as well as disputes with the coal lessees, or internal control deficiencies.

Defects in title in the coal properties that we own or loss of any leasehold interests could limit our ability to mine these properties or result in significant unanticipated costs.

We conduct a significant part of our mining operations on leased properties. A title defect or the loss of any lease could adversely affect our ability to mine the associated coal reserves. Title to most of our owned and leased properties and the associated mineral rights is not usually verified until we make a commitment to develop a property, which may not occur until after we have obtained necessary permits and completed exploration of the property. In some cases, we rely on title information or representations and warranties provided by our grantors or lessors, as the case may be. Our right to mine some coal reserves would be adversely affected by defects in title or boundaries or if a lease expires. Any challenge to our title or leasehold interest could delay the exploration and development of the property and could ultimately result in the loss of some or all of our interest in the property. Mining operations from time to time may rely on a lease that we are unable to renew on terms at least as favorable, if at all. In such event, we may have to close down or significantly alter the sequence of mining operations or incur additional costs to obtain or renew such leases, which could adversely affect our future coal production. If we mine on property that we do not control, we could incur liability for such mining. Our sponsor, Wexford Capital, will not indemnify us for losses attributable to title defects in the properties that we own or lease.

Our work force could become unionized in the future, which could adversely affect our production and labor costs and increase the risk of work stoppages.

Currently, none of our employees are represented under collective bargaining agreements. However, all of our work force may not remain union-free in the future. If some or all of our work force were to become unionized, it could adversely affect our productivity and labor costs and increase the risk of work stoppages.

We depend on key personnel for the success of our business.

We depend on the services of our senior management team and other key personnel, including senior management of our general partner. The loss of the services of any member of senior management or key employee could have an adverse effect on our business and reduce our ability to make distributions to our unitholders. We may not be able to locate or employ on acceptable terms qualified replacements for senior management or other key employees if their services were no longer available.

If the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, we could be required to expend greater amounts than anticipated.

The Federal Surface Mining Control and Reclamation Act of 1977 and counterpart state laws and regulations establish operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of underground mining. Estimates of our total reclamation and mine closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. The estimate of ultimate reclamation liability is reviewed both periodically by our management and annually by independent third-party engineers. The estimated liability can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. Please read “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Asset Retirement Obligations.” Wexford will not indemnify us against any reclamation or mine closing liabilities associated with our assets.

Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

Our level of indebtedness could have important consequences to us, including the following:

	●	•our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including acquisitions) or other purposes may be impaired or such financing may not be available on favorable terms;

	●	•covenants contained in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

	●	•we will need a portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, distributions to unitholders and future business opportunities;

	●	•we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

	●	•our flexibility in responding to changing business and economic conditions may be limited.

Increases in our total indebtedness would increase our total interest expense, which would in turn reduce our forecasted cash available for distribution. As of December 31, 2013 our current portion of long-term debt that will be funded from cash flows from operating activities during 2014 was approximately $1.0 million. Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms, or at all.

Our credit agreement contains operating and financial restrictions that may restrict our business and financing activities and limit our ability to pay distributions upon the occurrence of certain events.

The operating and financial restrictions and covenants in our credit agreement and any future financing agreements could restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities. For example, our credit agreement restricts our ability to:

	●	incur additional indebtedness or guarantee other indebtedness;

	●	grant liens;

	●	make certain loans or investments;

	●	dispose of assets outside the ordinary course of business, including the issuance and sale of capital stock of our subsidiaries;

	●	change the line of business conducted by us or our subsidiaries;

	●	enter into a merger, consolidation or make acquisitions; or

	●	make distributions if an event of default occurs.

In addition, our payment of principal and interest on our debt will reduce cash available for distribution on our units. Our credit agreement limits our ability to pay distributions upon the occurrence of the following events, among others, which would apply to us and our subsidiaries:

	●	failure to pay principal, interest or any other amount when due;

	●	breach of the representations or warranties in the credit agreement;

	●	failure to comply with the covenants in the credit agreement;

	●	cross-default to other indebtedness;

	●	bankruptcy or insolvency;

	●	failure to have adequate resources to maintain, and obtain, operating permits as necessary to conduct our operations substantially as contemplated by the mining plans used in preparing the financial projections; and

	●	a change of control.

Any subsequent refinancing of our current debt or any new debt could have similar restrictions. Our ability to comply with the covenants and restrictions contained in our credit agreement may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit agreement, a significant portion of our indebtedness may become immediately due and payable, and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit agreement will be secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit agreement, the lenders could seek to foreclose on such assets. For more information, please read “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement.”

Based on current projections, our current normal operating forecast indicates that we will not meet the conditions required to extend the expiration date of our amended and restated credit agreement from July 2016 to July 2017. As a result, our credit facility balance is classified on our statement of financial position as of September 30, 2015 as a current liability and this classification raises substantial doubt of our ability to continue as a going concern for the next twelve months.

In April 2015, we entered into a third amendment of our amended and restated senior secured credit facility. The third amendment extended the expiration date of the amended and restated credit agreement to July 2017. The extension is contingent upon (i) our leverage ratio being less than or equal to 2.75 to 1.0 and (ii) our having liquidity greater than or equal to $15 million, in each case for either the quarter ending December 31, 2015 or March 31, 2016. If both of these conditions are not satisfied for either quarter, the expiration date of the amended and restated credit agreement will revert to July 2016, at which time we will be required to repay all of the outstanding borrowings thereunder. As of September 30, 2015, our ratio was 3.2 to 1.0 and our liquidity was approximately $9.0 million. Based on current projections, our current normal operating forecast indicates that we will not meet both of these extension conditions for either quarter without a waiver. Based on this analysis, we determined that our credit facility debt liability of $48.0 million at September 30, 2015 should be classified as a current liability on our unaudited condensed consolidated statements of financial position. The classification of our credit facility balance as a current liability raises substantial doubt of our ability to continue as a going concern for the next twelve months. If we are unable to meet the extension conditions under our amended and restated senior secured credit facility and the expiration date of the credit agreement reverts to July 2016, we will have to secure alternative financing to replace our credit facility by the expiration date of July 2016 in order to continue our normal business operations, and there can be no assurance that we would be able to obtain adequate alternative financing on acceptable terms or at all.

There are other uncertainties as to our ability to access funding under our amended and restated credit agreement. In order to borrow under our amended and restated credit facility, we must make certain representations and warranties to our lenders at the time of each borrowing. If we are unable to make these representations and warranties, we would be unable to borrow under our amended and restated credit facility, absent a waiver. Furthermore, if we violate any of the covenants or restrictions in our amended and restated credit agreement, including the maximum leverage ratio and the minimum fixed charge coverage ratio, some or all of our indebtedness may become immediately due and payable, and our lenders’ commitment to make further loans to us may terminate. Given the continued weak demand and low prices for met and steam coal, we may not be able to continue to give the required representations or meet all of the covenants and restrictions included in our credit facility. If we are unable to give a required representation or we violate a covenant or restriction, then we will need a waiver from our lenders in order to continue to borrow under our amended and restated credit agreement.

Our principal liquidity requirements are to finance current operations, fund capital expenditures and service our debt. Our principal sources of liquidity are cash generated by our operations and borrowings under our credit agreement. If we are unable to extend the expiration date of our amended and restated credit facility or secure a replacement facility or borrow under our existing credit facility, we will lose a primary source of liquidity, and we may not be able to generate adequate cash flow from operations to fund our business. Failure to obtain financing or to generate sufficient cash flow from operations could cause us to significantly reduce our spending and to alter our short- or long-term business plan. We may also be required to consider other options, such as selling assets or merger opportunities, and depending on the urgency of our liquidity constraints, we may be required to pursue such an option at an inopportune time. If we are not able to fund our liquidity requirements for the next twelve months, we may not be able to continue as a going concern.

Although we monitor our level of non-qualifying income closely and attempt to manage our operations to ensure compliance with the qualifying income requirement, given the continued weak demand and low prices for met and steam coal, there is a risk that we will not be able to continue to meet the qualifying income level necessary to maintain our status as a partnership for federal income tax purposes.

As a publicly traded partnership, we may be treated as a corporation for federal income tax purposes unless 90% or more of our gross income in each year consists of certain identified types of “qualifying income.” In addition to qualifying income, like many other publicly traded partnerships, we also generate ancillary income that may not constitute qualifying income. Although we monitor our level of gross income that may not constitute qualifying income closely and attempt to manage our operations to ensure compliance with the qualifying income requirement, given the continued weak demand and low prices for met and steam coal, the sale of which generates qualifying income, there is a risk that we will not be able to continue to meet the qualifying income level necessary to maintain our status as a publicly-traded partnership. To the extent we become aware that we may not generate or have not generated sufficient qualifying income with respect to a period, we can and would take action to preserve our treatment as a partnership for federal income tax purposes, including seeking relief from the IRS. Section 7704(e) of the Internal Revenue Code provides for the possibility of relief upon, among other things, determination by the IRS that such failure to meet the qualifying income requirement was inadvertent. However, we are unaware of examples of such relief being sought by a publicly traded partnership.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, the Obama administration’s budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, the Obama administration’s proposal, or other similar proposals, could eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations, upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

In addition, the IRS, on May 5, 2015, issued proposed regulations concerning which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code. We do not believe the proposed regulations affect our ability to qualify as a publicly traded partnership. However, finalized regulations could modify the amount of our gross income that we are able to treat as qualifying income for the purposes of the qualifying income requirement and modify or revoke existing private letter rulings, including ours.

Any modifications to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

Royal Energy Resources, Inc. - FORM 8-K - February 5, 2016

Royal Energy Resources, Inc. Reports