Exhibit 99.2
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion of the historical financial condition and results of operations should be read in conjunction with the historical financial statements and accompanying notes included elsewhere in this report. In addition, this discussion includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from statements we make. See “Cautionary Note Regarding Forward- Looking Statements.” Factors that could cause actual results to differ include those risks and uncertainties discussed in Part I, Item 1A. “Risk Factors.”
Prior to the issuance of our 2013 financial statements, a determination was made that we had incorrectly calculated and reported our liability and costs for black lung benefits. We had previously accounted for our black lung benefit liability using an event driven approach under Accounting Standard Codification (“ASC”) No. 450, Contingencies. It was determined the we should have accounted for our black lung benefit liability using a service cost approach under ASC 710, Compensation General, because this approach matches black lung costs over the service lives of the miners who ultimately receive black lung benefits. We determined that the effect of this error was not material to our financial statements and disclosures taken as a whole for any period presented. Our financial statements for the years ended December 31, 2012 and 2011 have been revised from the amounts previously reported to correctly report our liability and costs for black lung benefits. The financial statement items impacted include Cost of operations and Equity in net (loss)/income of unconsolidated affiliates in the consolidated statements of operations and comprehensive income and Investments in unconsolidated affiliates, Other non-current assets and Other non-current liabilities in our consolidated statements of financial position. These adjustments had no impact on our consolidated statements of cash flows. The following discussion of our operating results includes revised financial data for the 2012 and 2011 periods.
In March 2014, we completed a purchase and sale agreement with Gulfport Energy to sell our oil and gas properties in the Utica Shale region for approximately $184.0 million. Our consolidated statements of operations and comprehensive income have been retrospectively adjusted to reclassify our portion of our Utica Shale operations to discontinued operations for the years ended December 31, 2013 and 2012. Our Utica Shale investment did not have any operating activity during the year ended December 31, 2011. The following discussion of our operating results includes revised financial data for the 2013 and 2012 periods.
Overview
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. 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 those management and leasing activities. Our diversified energy portfolio also includes investments in oil and natural gas mineral rights in the Cana Woodford region of western Oklahoma and an investment in the Utica Shale region of eastern Ohio, which we signed a binding letter of intent to sell to a third party for $185 million in February 2014 (details discussed further below). We receive royalty revenue from any hydrocarbons produced and sold by operators on our Cana Woodford acreage. In addition, we have expanded our business to include infrastructure support services, including the formation of Razorback, 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. In December 2012, we also invested in a joint venture that will provide sand for fracking operations to drillers in the Utica Shale region and other oil and natural gas basins in the U.S.
We and an affiliate of Wexford participated with Gulfport Energy (“Gulfport”), a publicly traded company, to acquire interests in a portfolio of oil and natural gas leases in the Utica Shale. Our initial position in the Utica Shale consisted of a 10.8% net interest in approximately 80,000 gross acres. During the third quarter of 2012, we completed an exchange of our initial 10.8% position for a pro rata interest in 125,000 gross acres under lease by Gulfport and an affiliate of Wexford Capital. Also during the third quarter of 2012, our position was adjusted to a 5% net interest in the 125,000 gross acres, or approximately 6,250 net acres. As of December 31, 2013, our Utica Shale position consisted of our 5% net interest in a total portfolio of approximately 152,300 gross acres, or approximately 7,615 net acres, for a total purchase price of approximately $31.1 million. In addition, per the joint operating agreement among Rhino, Gulfport and an affiliate of Wexford Capital, we funded our proportionate share of drilling costs to Gulfport for wells drilled on our acreage. As of December 31, 2013, we funded approximately $23.3 million of drilling costs. We received approximately $5.6 million of revenue from this investment for the year ended December 31, 2013.
In February 2014, we signed a binding letter of intent to sell our entire Utica Shale joint interest investment to Gulfport for $185 million, subject to customary closing conditions. The expected sale of our investment in the Utica Shale will allow us to eliminate substantially all of our debt and will give us significant financial flexibility. The elimination of our debt provides us the capability to opportunistically expand our operations and increase our cash flow through the development of existing coal reserves or the potential acquisition of MLP qualifying assets.
In March 2014, we completed a purchase and sale agreement (the “Purchase Agreement”) with Gulfport to sell our oil and gas properties in the Utica Shale region for approximately $184.0 million (the “Purchase Price”). The Purchase Agreement was effective as of January 1, 2014 and the Purchase Price was adjusted for any unsettled expenditures made and/or proceeds received from our portion of its Utica Shale properties prior to the effective date. Our consolidated statements of operations and comprehensive income have been retrospectively adjusted to reclassify our portion of our Utica Shale operations to discontinued operations for the years ended December 31, 2013 and 2012. Our Utica Shale investment did not have any operating activity during the year ended December 31, 2011. The net effect of the reclassification represents a decrease of $1.3 million, or 13.9%, and $0.1 million, or 0.2%, in our previously reported income from continuing operations for the years ended December 31, 2013 and 2012, respectively. We also reclassified certain current assets, non-current assets, current liabilities and non-current liabilities to “held for sale” categories on the consolidated statements of financial position for the years ended December 31, 2013 and 2012. There was no effect on our previously reported net income, financial condition, or cash flows
We have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region and oil and natural gas investments in the Cana Woodford region in western Oklahoma. As of December 31, 2013, we controlled an estimated 457.7 million tons of proven and probable coal reserves, consisting of an estimated 438.0 million tons of steam coal and an estimated 19.7 million tons of metallurgical coal. In addition, as of December 31, 2013, we controlled an estimated 277.0 million tons of non-reserve coal deposits. As of December 31, 2013, Rhino Eastern LLC, a joint venture in which we have a 51% membership interest and for which we serve as manager, controlled an estimated 43.9 million tons of proven and probable coal reserves at the Rhino Eastern mining complex located in Central Appalachia, consisting entirely of premium mid-vol and low-vol metallurgical coal, and an estimated 18.8 million tons of non-reserve coal deposits. As of December 31, 2013, we operated eight mines, including four underground and four surface mines, located in Kentucky, Ohio, West Virginia and Utah. In addition, our joint venture operated one underground mine in West Virginia. We also had one underground mine located in Colorado 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). The number of mines that we operate may vary from time to time depending on a number of factors, including the demand for and price of coal, depletion of economically recoverable reserves and availability of experienced labor. Our oil and natural gas investments as of December 31, 2013 also consisted of approximately 1,900 net mineral acres that we own in the Cana Woodford region..
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 continue to expand and potentially diversify our operations through strategic acquisitions, including the acquisition of long-term, cash generating natural resource assets, such as our oil and gas investments in the Cana Woodford region. We believe that such assets will allow us to grow our cash available for distribution and enhance our cash flow.
For the year ended December 31, 2013, we generated revenues of approximately $272.2 million and net income from continuing operations of approximately $8.1 million. Our total net income for the year ended December 31, 2013 was approximately $9.4 million, which includes approximately $1.3 million of income from discontinued operations related to our Utica Shale investment. Excluding results from the Rhino Eastern joint venture, for the year ended December 31, 2013, we produced approximately 3.6 million tons of coal, purchased approximately 0.1 million tons of coal and sold approximately 3.7 million tons of coal, approximately 88% of which were pursuant to supply contracts. Additionally, Rhino Eastern produced and sold approximately 0.2 million tons of premium mid-vol metallurgical coal for the year ended December 31, 2013.
Recent Developments
Follow-on Offering
On September 13, 2013, we completed a public offering of 1,265,000 common units, representing limited partner interests in us, at a price of $12.30 per common unit. Of the common units issued, 165,000 units were issued in connection with the exercise of the underwriters’ option to purchase additional units. Net proceeds from the offering were approximately
$14.6 million, after deducting underwriting discounts and offering expenses of approximately $1.0 million. We used the net proceeds from this offering, and a related capital contribution by our general partner of approximately $0.3 million, to repay approximately $14.9 million of outstanding indebtedness under our credit facility.
Credit Facility
In April 2013, we entered into an amendment of our amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and a group of lenders, which are parties thereto. The amendment provided for an increase in the maximum allowed investments in coal-related entities outside of our current organization (i.e. joint ventures) under the amended and restated senior secured credit facility from $25 million to $40 million. The amendment also increased the maximum leverage ratio allowed under the amended and restated senior secured credit facility and also altered the pricing grid to include applicable interest rates for borrowings, letter of credit fees and commitment fees on unused borrowings based upon the new maximum leverage ratio. The amendment increased the maximum leverage ratio of the amended and restated senior secured credit facility to 3.75 from April 1, 2013 through March 31, 2015, then steps the maximum leverage ratio down to its previous level of 3.0 after December 31, 2015. All other terms of the amended and restated senior secured credit facility were not affected by the amendment.
Patriot Coal Corporation Bankruptcy
We have a 51% equity interest in the Rhino Eastern joint venture, with Patriot Coal Corporation (“Patriot”) owning the remaining membership interest. On July 9, 2012, Patriot filed for Chapter 11 bankruptcy protection and Patriot successfully exited bankruptcy in December 2013.
Acquisition of Coal Property
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 for approximately $1.5 million. In addition, we could potentially be required to pay an additional $3.0 million related to this acquisition if certain conditions are met. Of that amount, $2.0 million was initially recorded in in Property, plant and equipment and Accrued expenses related to this acquisition since this additional amount related to the purchase of these assets was probable and estimable. As of December 31, 2013, we have paid the $2.0 million since the conditions requiring payment had been met. The remaining $1.0 million in potential payments has not been recorded because the conditions requiring payment of this amount have not yet occurred.
The coal leases and property are estimated to contain approximately 32.6 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. Initial development of this property has commenced and initial production and sales from our new mine on this property, referred to as the Riveredge mine, is expected to occur in mid-2014.
Oil and Gas Investments
In 2011 we began to invest in oil and natural gas mineral rights in the Utica Shale region of eastern Ohio. As of December 31, 2013, we had invested a total of approximately $31.1 million for a 5% net interest in a portfolio of oil and natural gas leases in the Utica Shale region along with approximately $23.3 million in drilling costs, which represented our proportionate ownership share in the portfolio. Gulfport, the operator of the portfolio, began drilling and testing wells in the region in 2012 and we received our proportionate share (5%) of revenue from the hydrocarbons produced and sold by the operator on our acreage, which totaled approximately $5.6 million for the year ended December 31, 2013. In February 2014, we signed a binding letter of intent to sell our entire Utica Shale joint interest investment to Gulfport for $185 million. In March 2014, we completed the Purchase Agreement with Gulfport to sell our oil and gas properties in the Utica Shale region for approximately $184.0 million, as discussed earlier.
In March 2012, we completed an out-lease agreement with a third party for approximately 1,232 acres we own in the Utica Shale region of Harrison County Ohio. The lease agreement is for an initial five year term with an optional three year renewal period and conveys rights to the lessee to perform drilling and operating activities for producing oil, natural gas or other hydrocarbons. As part of the lease agreement, the third party agreed to pay us the sum of $6,000 per acre as a lease bonus, of which $0.5 million was paid at the signing of the lease agreement. An additional $6.9 million was paid in the second quarter of 2012 totaling approximately $7.4 million of lease bonus payments for approximately 1,232 acres. In addition, the lease agreement stipulates that the third party shall pay us a 20% royalty based upon the gross proceeds received from the sale of oil and/or natural gas recovered from the leased property.
In April 2013, we completed an agreement with a third party to sell the 20% royalty interest for approximately $10.5 million on the 1,232 acres in the Utica Shale. The sale of the royalty interest resulted in a gain of approximately $10.5 million since we had no cost basis associated with the royalty interest.
In September 2013, we completed an agreement with a third party to sell the oil and natural gas mineral rights for approximately 57 acres we own in the Utica Shale region in Harrison County, Ohio for approximately $0.6 million. The sale of this acreage resulted in a gain of approximately $0.6 million since we had no cost basis associated with this property.
We have invested in certain oil and natural gas mineral rights in the Cana Woodford region of western Oklahoma for a total purchase price of approximately $8.1 million. Our investment includes approximately 1,900 net mineral acres that we own in the Cana Woodford region which provide monthly royalty revenue to Rhino.
Other Investments
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 portion of the operating loss for the years ended December 31, 2013 and 2012 of approximately $0.5 million and $0.3 million, respectively. During the year ended December 31, 2013, we contributed additional capital based upon our ownership share to the Muskie joint venture in the amount of $0.5 million. In addition, during the year ended December 31, 2013, the Partnership provided a loan based upon its ownership share to Muskie in the amount of $0.2 million that remained outstanding as of December 31, 2013.
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 share to purchase land for the construction site of the condensate river terminal. Timber Wolf had no operating activities during the years ended December 31, 2013 and 2012.
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 completed the construction and upgrade of eleven drill pads during the year ended December 31, 2013 in addition to the three drill pads completed during 2012. Two impoundments for fracking water were also constructed during 2013 for a total of three completed to date. Additionally, Razorback has constructed several access roads for operators in the Utica Shale region.
Sale of Land Surface Rights
In December 2012, we completed the sale of the surface rights to approximately 134 acres located in Harrison County, Ohio for approximately $1.5 million. We recorded a gain of approximately $1.5 million related to this sale that is included on the (Gain) on sale/disposal of assets—net line of our consolidated statements of operations and comprehensive income.
Sale of Triad Operations
In August 2012, we sold the operations and tangible assets of our roof bolt manufacturing company, Triad, to a third party for $0.5 million of cash consideration. As part of the sale, we retained the rights to certain intellectual property and entered into an exclusive license and option to purchase agreement for this intellectual property with the same third party for potential additional cash consideration. We have not recorded any portion of this additional consideration since this amount is contingent upon the third party determining the viability of the related intellectual property to their specifications, which has since expired. In connection with this sale, we recorded an approximate $0.2 million gain that is recorded on the (Gain) on sale/disposal of assets—net line of our consolidated statements of operations and comprehensive income.
Sale of Mining Assets
In December 2012, we sold certain non-core mining assets located in Pike County, Kentucky to a third party for approximately $0.2 million. The transaction also extinguished certain liabilities related to the assets sold. In relation to the sale of these assets and extinguishment of liabilities, we recorded a gain of approximately $0.9 million, which was higher
than the sales amount due to the extinguishment of the liabilities. This gain is included on the (Gain) on sale/disposal of assets—net line of the Partnership’s consolidated statements of operations and comprehensive income.
In February 2012, we sold certain non-core mining assets located in Pike County, Kentucky to a third party for approximately $0.6 million. The transaction also extinguished certain liabilities related to the assets sold. In relation to the sale of these assets and extinguishment of liabilities, we recorded a gain of approximately $0.9 million, which was higher than the sales amount due to the extinguishment of the liabilities.
Factors That Impact Our Business
Our results of operations in the near term could be impacted by a number of factors, including (1) adverse weather conditions and natural disasters, (2) poor mining conditions resulting from geological conditions or the effects of prior mining, (3) equipment problems at mining locations, (4) the availability of transportation for coal shipments or (5) the availability and costs of key supplies and commodities such as steel, diesel fuel and explosives.
On a long-term basis, our results of operations could be impacted by, among other factors, (1) changes in governmental regulation, (2) the availability and prices of competing electricity-generation fuels, (3) the world-wide demand for steel, which utilizes metallurgical coal and can affect the demand and prices of metallurgical coal that we produce, (4) our ability to secure or acquire high-quality coal reserves and (5) our ability to find buyers for coal under favorable supply contracts.
We have historically sold a majority of our coal through supply contracts and anticipate that we will continue to do so. As of December 31, 2013, we had commitments under supply contracts to deliver annually scheduled base quantities of coal as follows:
Year | | Tons (in
thousands) | | Number of
customers | |
2014 | | 3,045 | | 19 | |
2015 | | 1,796 | | 4 | |
2016 | | 1,100 | | 2 | |
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.
Results of Operations
Segment Information
We conduct business through five reportable business segments: Central Appalachia, Northern Appalachia, Eastern Met, Rhino Western and Oil and Natural Gas. Additionally, we have an Other category that includes our ancillary businesses. Our Central Appalachia segment consists of three mining complexes: Tug River, Rob Fork and Deane, which, as of December 31, 2013, together included two underground mines, three surface mines and four preparation plants and loadout facilities in eastern Kentucky and southern West Virginia. Additionally, our Central Appalachia segment includes the Elk Horn operations. Our Northern Appalachia segment consists of the Hopedale mining complex, the Sands Hill mining complex, the Leesville field and the Springdale field. The Hopedale mining complex, located in northern Ohio, included one underground mine and one preparation plant and loadout facility as of December 31, 2013. Our Sands Hill mining complex, located in southern Ohio, included two surface mines, a preparation plant and a river terminal as of December 31, 2013. The Eastern Met segment includes our 51% equity interest in the results of operations of the Rhino Eastern joint venture, which owns the Rhino Eastern mining complex, located in West Virginia, and for which we serve as manager. As of December 31, 2013, this complex was comprised of one underground mine and a preparation plant and loadout facility (owned by our joint venture partner). Our Rhino Western segment included our two underground mines in the Western Bituminous region that consisted of our McClane Canyon mine in Colorado that was permanently idled at the end of 2013 and our Castle Valley mining complex in Utah that began production in January 2011.
Beginning with 2013 year-end reporting, we initially included a reportable business segment for our oil and natural gas activities since the total assets for these operations met the quantitative threshold for separate segment reporting. The Oil and Natural Gas segment included our Utica Shale activities, which were sold during the first quarter of 2014 as described earlier, as well as our Cana Woodford activities, our Razorback drill pad construction operations and our Muskie joint venture to provide sand for fracking operations. Prior to 2013, our oil and natural gas activities were included in our Other category for segment reporting purposes. Since the majority of our oil and natural gas activities were in the Utica Shale and the Utica Shale financial results have been reclassified in discontinued operations due to their sale, the segment data for our
remaining oil and natural gas activities have been reclassified in the Other category for segment reporting purposes for all periods presented since they are not material for separate segment reporting. Our Other category as reclassified is comprised of our ancillary businesses and our remaining oil and natural gas activities.
During 2012, we changed the method that allocates certain corporate overhead and interest charges to our reportable segments from a method based on production tons to a method based upon the amount invested in fixed assets. We changed the allocation method as a result of additional investments that we made in our non-coal operations. The reportable segment figures in the following discussion and analysis have been re-cast for 2011.
Evaluating Our Results of Operations
Our management uses a variety of financial measurements to analyze our performance, including (1) Adjusted EBITDA, (2) coal revenues per ton and (3) cost of operations per ton.
Adjusted EBITDA. The discussion of our results of operations below includes references to, and analysis of, our segments’ Adjusted EBITDA results. Adjusted EBITDA represents net income before deducting interest expense, income taxes and depreciation, depletion and amortization, including our proportionate share of these expense items from our Rhino Eastern LLC joint venture, while also excluding certain non-cash and/or non-recurring items. Adjusted EBITDA is used by management primarily as a measure of our segments’ operating performance. Adjusted EBITDA should not be considered an alternative to net income, income from operations, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Because not all companies calculate EBITDA identically, our calculation may not be comparable to similarly titled measures of other companies. Please read “—Reconciliation of Adjusted EBITDA to Net Income by Segment” for reconciliations of Adjusted EBITDA to net income by segment for each of the periods indicated.
Coal Revenues Per Ton. Coal revenues per ton represents coal revenues divided by tons of coal sold. Coal revenues per ton are a key indicator of our effectiveness in obtaining favorable prices for our product.
Cost of Operations Per Ton. Cost of operations per ton sold represents the cost of operations (exclusive of DD&A) divided by tons of coal sold. Management uses this measurement as a key indicator of the efficiency of operations.
Summary
The following table sets forth certain information regarding our revenues, operating expenses, other income and expenses, and operational data for years ended December 31, 2013, 2012 and 2011:
| | Year Ended December 31, | |
| | 2013 | | 2012 | | 2011 | |
| | (in millions) | |
Statement of Operations Data: | | | | | | | |
Total revenues | | $ | 272.2 | | $ | 351.7 | | $ | 367.2 | |
Costs and expenses: | | | | | | | |
Cost of operations (exclusive of DD&A shown separately below) | | 199.7 | | 247.7 | | 267.7 | |
Freight and handling costs | | 1.3 | | 5.8 | | 4.3 | |
Depreciation, depletion and amortization | | 39.6 | | 41.3 | | 36.3 | |
Selling, general and administrative (exclusive of DD&A shown separately above) | | 19.8 | | 20.5 | | 21.8 | |
Asset impairment loss | | 1.7 | | — | | — | |
(Gain) on sale/disposal of assets | | (10.4 | ) | (4.9 | ) | (3.2 | ) |
Income from operations | | 20.5 | | 41.3 | | 40.3 | |
Interest and other income (expense): | | | | | | | |
Interest expense and other | | (7.9 | ) | (7.8 | ) | (6.1 | ) |
Interest income and other | | 0.2 | | 0.1 | | 0.1 | |
Equity in net (loss)/income of unconsolidated affiliates | | (4.7 | ) | 5.8 | | 3.0 | |
Total interest and other income (expense) | | (12.4 | ) | (1.9 | ) | (3.0 | ) |
Net income from continuing operations | | 8.1 | | 39.4 | | 37.3 | |
Net income from discontinued operations | | 1.3 | | 0.1 | | — | |
Net income | | $ | 9.4 | | $ | 39.5 | | $ | 37.3 | |
| | | | | | | |
Other Financial Data | | | | | | | |
Adjusted EBITDA from continuing operations | | $ | 59.2 | | $ | 89.6 | | $ | 81.2 | |
Net income from discontinued operations | | 1.3 | | 0.1 | | — | |
DD&A included in net income from discontinued operations | | 3.0 | | 0.1 | | — | |
Total Adjusted EBITDA | | $ | 63.5 | | $ | 89.8 | | $ | 81.2 | |
Year Ended December 31, 2013 Compared to Year Ended December 31, 2012
Summary. For the year ended December 31, 2013, our total revenues decreased to $272.2 million from $351.7 million for the year ended December 31, 2012. We sold 3.7 million tons of coal for the year ended December 31, 2013, which is 1.0 million tons less, or a 21.4% decrease, than the 4.7 million tons of coal sold for the year ended December 31, 2012. This decrease in tons sold was the result of weak demand in the steam coal markets, which resulted in lower coal revenues for 2013 compared to 2012. Coal revenues in 2013 were also negatively impacted by weak met coal prices compared to 2012 levels. We believe the weak demand in the steam coal markets was primarily driven by an over-supply of low priced natural gas that increased stockpiles of coal at electric utilities. We believe utilities are still working to decrease their coal stockpiles, which has extended the weakness in the steam coal markets even though natural gas prices have risen from their previous historic lows. We believe the weak prices in the met coal markets were primarily driven by a decrease in world-wide steel production due to economic weakness in China and Europe.
For the year ended December 31, 2013, our coal inventories decreased by approximately 28,000 tons from the year ended December 31, 2012 as we lowered production levels and sold excess inventory tons.
Net income from continuing operations was $8.1 million for the year ended December 31, 2013 compared to $39.4 million for the year ended December 31, 2012. Adjusted EBITDA from continuing operations decreased to $59.2 million for the year ended December 31, 2013, from $89.6 million for the year ended December 31, 2012. Net income from continuing operations and Adjusted EBITDA from continuing operations decreased year to year as reductions in costs were offset by lower coal revenues. For the year ended December 31, 2013, our net income from continuing operations and Adjusted EBITDA from continuing operations was positively impacted by $10.5 million from the sale of our 20% royalty interest on our Utica Shale property, while net income for this period was negatively impacted by approximately $0.9 million due to the non-cash write-off of a continuous miner that was damaged at one of our Central Appalachia underground mines
and by approximately $1.7 million due to an asset impairment loss from permanently idling our McClane Canyon mine. For the year ended December 31, 2012, net income from continuing operations and Adjusted EBITDA from continuing operations was positively impacted by the $7.4 million lease bonus payments received for our Utica Shale acreage, which had relatively immaterial costs associated with the transaction. The Utica Shale transactions discussed above related to property we previously owned and was not part of the Utica Shale sale transaction with Gulfport in March 2014, which is why these transactions are included in continuing operations. Net income from continuing operations and Adjusted EBITDA from continuing operations were negatively impacted in 2013 due to approximately $4.3 million of net loss from our Rhino Eastern joint venture compared to income of $6.0 million for 2012, each of which represents our proportionate share of income from the Rhino Eastern joint venture in which we have a 51% membership interest and for which we serve as manager.
Including the income from discontinued operations of approximately $1.3 million from our Utica Shale activities, our total net income for the year ended December 31, 2013 was approximately $9.4 million and our total Adjusted EBITDA was $63.5 million when our discontinued operations items are included. Including discontinued operations items for the year ended December 31, 2012, our total net income and Adjusted EBITDA were approximately $39.5 million and $89.8 million, respectively. The year to year decrease in total net income and Adjusted EBITDA are due to the same factors discussed above for the year to year decrease in net income from continuing operations and Adjusted EBITDA from continuing operations.
Tons Sold. The following table presents tons of coal sold by reportable segment for the years ended December 31, 2013 and 2012:
| | | | | | Increase | | | |
| | Year Ended | | Year Ended | | (Decrease) | | | |
Segment | | December 31, 2013 | | December 31, 2012 | | Tons | | % * | |
| | (in thousands, except %) | |
Central Appalachia | | 1,507.7 | | 1,756.1 | | (248.4 | ) | (14.1 | )% |
Northern Appalachia | | 1,225.0 | | 1,875.1 | | (650.1 | ) | (34.7 | )% |
Rhino Western | | 940.2 | | 1,038.9 | | (98.7 | ) | (9.5 | )% |
Total *† | | 3,672.9 | | 4,670.1 | | (997.2 | ) | (21.4 | )% |
* Calculated percentages and the rounded totals presented are based upon on actual whole ton amounts and not the rounded amounts presented in this table.
† Excludes tons sold by the Rhino Eastern joint venture, which owns the Rhino Eastern mining complex located in West Virginia and for which we serve as manager.
We sold approximately 3.7 million tons of coal in the year ended December 31, 2013 as compared to approximately 4.7 million tons sold for the year ended December 31, 2012. This decrease in tons sold was primarily due to weakness in the steam coal markets, primarily in Northern Appalachia and Central Appalachia. Tons of coal sold in our Central Appalachia segment decreased by approximately 0.3 million, or 14.1%, to approximately 1.5 million tons for the year ended December 31, 2013 from approximately 1.8 million tons for the year ended December 31, 2012. The decrease in total tons sold year-to-year in Central Appalachia was primarily due to weakness in the steam coal markets, partially offset by an increase in met coal tons sold as met coal sales in the spot market increased in 2013 compared to 2012. For our Northern Appalachia segment, tons of coal sold decreased by approximately 0.7 million, or 34.7%, to approximately 1.2 million tons for the year ended December 31, 2013 from approximately 1.9 million tons for the year ended December 31, 2012. The decrease in total tons sold year-to-year was primarily due to lower sales from our Sands Hill complex in Northern Appalachia as market conditions for coal from this operation weakened year-to-year, as well as slightly fewer tons sold at our Hopedale complex. Coal sales from our Rhino Western segment decreased by approximately 0.1 million, or 9.5%, to approximately 0.9 million tons for the year ended December 31, 2013 from approximately 1.0 million tons for the year ended December 31, 2012 as our Castle Valley mine continued to fulfill contracted customer shipments, but had fewer spot sales in 2013 compared to 2012.
Revenues. The following table presents revenues and coal revenues per ton by reportable segment for the years ended December 31, 2013 and 2012:
| | Year ended | | Year ended | | Increase/(Decrease) | | | |
Segment | | December 31, 2013 | | December 31, 2012 | | $ | | % * | |
| | (in millions, except per ton data and %) | |
Central Appalachia | | | | | | | | | |
Coal revenues | | $ | 126.4 | | $ | 161.3 | | $ | (34.9 | ) | (21.6 | )% |
Freight and handling revenues | | — | | — | | — | | n/a | |
Other revenues | | 21.0 | | 22.1 | | (1.1 | ) | (4.9 | )% |
Total revenues | | $ | 147.4 | | $ | 183.4 | | $ | (36.0 | ) | (19.6 | )% |
Coal revenues per ton* | | $ | 83.85 | | $ | 91.83 | | $ | (7.98 | ) | (8.7 | )% |
Northern Appalachia | | | | | | | | | |
Coal revenues | | $ | 72.2 | | $ | 102.9 | | $ | (30.7 | ) | (29.8 | )% |
Freight and handling revenues | | 2.2 | | 6.3 | | (4.1 | ) | (66.1 | )% |
Other revenues | | 6.0 | | 12.8 | | (6.8 | ) | (52.9 | )% |
Total revenues | | $ | 80.4 | | $ | 122.0 | | $ | (41.6 | ) | (34.1 | )% |
Coal revenues per ton* | | $ | 58.95 | | $ | 54.87 | | $ | 4.08 | | 7.4 | % |
Rhino Western | | | | | | | | | |
Coal revenues | | $ | 38.0 | | $ | 40.4 | | $ | (2.4 | ) | (6.1 | )% |
Freight and handling revenues | | — | | — | | — | | n/a | |
Other revenues | | 0.3 | | 0.3 | | — | | 0.3 | % |
Total revenues | | $ | 38.3 | | $ | 40.7 | | $ | (2.4 | ) | (6.0 | )% |
Coal revenues per ton* | | $ | 40.37 | | $ | 38.89 | | $ | 1.48 | | 3.8 | % |
Other** | | | | | | | | | |
Coal revenues | | n/a | | n/a | | n/a | | n/a | |
Freight and handling revenues | | n/a | | n/a | | n/a | | n/a | |
Other revenues | | $ | 6.1 | | $ | 5.6 | | $ | 0.5 | | 9.5 | % |
Total revenues | | $ | 6.1 | | $ | 5.6 | | $ | 0.5 | | 9.5 | % |
Coal revenues per ton* | | n/a | | n/a | | n/a | | n/a | |
Total | | | | | | | | | |
Coal revenues | | $ | 236.6 | | $ | 304.6 | | $ | (68.0 | ) | (22.3 | )% |
Freight and handling revenues | | 2.2 | | 6.3 | | (4.1 | ) | (66.0 | )% |
Other revenues | | 33.4 | | 40.8 | | (7.4 | ) | (17.9 | )% |
Total revenues | | $ | 272.2 | | $ | 351.7 | | $ | (79.5 | ) | (22.6 | )% |
Coal revenues per ton* | | $ | 64.42 | | $ | 65.22 | | $ | (0.80 | ) | (1.2 | )% |
* Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.
** The Oil and Natural Gas segment does not relate to coal production. The Other category includes results for our ancillary businesses. The activities performed by these ancillary businesses also do not directly relate to coal production. As a result, coal revenues and coal revenues per ton are not presented for the Oil and Natural Gas segment or the Other category.
Our total revenues for the year ended December 31, 2013 decreased by $79.5 million, or 22.6%, to $272.2 million from $351.7 million for the year ended December 31, 2012. The decrease in total revenues was primarily due to lower coal revenues from fewer steam coal tons sold and lower met coal prices in Central Appalachia, as well as fewer tons sold from our Sands Hill complex in Northern Appalachia as market conditions for coal from this operation weakened year-to-year. Coal revenues per ton were $64.42 for the year ended December 31, 2013, a decrease of $0.80, or 1.2%, from $65.22 per ton for the year ended December 31, 2012. This decrease in coal revenues per ton was primarily the result of lower prices for met coal sold in Central Appalachia, partially offset by an increase in coal revenues per ton in our Northern Appalachia segment primarily due to fewer lower priced tons being sold from our Sands Hill complex in 2013 compared to 2012.
For our Central Appalachia segment, coal revenues decreased by $34.9 million, or 21.6%, to $126.4 million for the year ended December 31, 2013 from $161.3 million for the year ended December 31, 2012 primarily due to fewer steam coal tons sold and a decrease in the price for met coal tons sold. Coal revenues per ton for our Central Appalachia segment decreased by $7.98, or 8.7%, to $83.85 per ton for the year ended December 31, 2013 as compared to $91.83 for the year ended December 31, 2012, primarily due to lower price for metallurgical coal sold. Other revenues decreased for our Central Appalachia segment primarily due to lower coal royalty revenue from our coal leasing operations as our lessees had lower selling prices for their coal in 2013 compared to 2012.
For our Northern Appalachia segment, coal revenues were $72.2 million for the year ended December 31, 2013, a decrease of $30.7 million, or 29.8%, from $102.9 million for the year ended December 31, 2012. This decrease was primarily due to fewer tons sold from our Sands Hill complex in Northern Appalachia as mentioned earlier and slightly fewer tons sold at our Hopedale complex. Coal revenues per ton for our Northern Appalachia segment increased by $4.08, or 7.4%, to $58.95 per ton for the year ended December 31, 2013 as compared to $54.87 per ton for the year ended December 31, 2012. This increase was primarily due to fewer lower priced tons being sold from our Sands Hill complex as market conditions for coal from this operation weakened year-to-year. Other revenues decreased for our Northern Appalachia segment primarily due to the $7.4 million lease bonus received in 2012 for acreage owned in the Utica Shale region that was not present in the 2013 comparable period. The Utica Shale transaction discussed above related to property we previously owned and was not part of the Utica Shale sale transaction with Gulfport in March 2014, which is why this transaction is included in continuing operations.
For our Rhino Western segment, coal revenues decreased by $2.4 million, or 6.1%, to $38.0 million for the year ended December 31, 2013 from $40.4 million for the year ended December 31, 2012 due to slightly fewer tons sold from our Castle Valley mine. Coal revenues per ton for our Rhino Western segment were $40.37 for the year ended December 31, 2013, an increase of $1.48, or 3.8%, from $38.89 for the year ended December 31, 2012. The increase in coal revenues per ton was due to a decrease in lower-priced spot sales from our Castle Valley mine in 2013 when compared to 2012.
Other revenues for our Other category increased by $0.5 million for the year ended December 31, 2013 from the year ended December 31, 2012. The increase in other revenues was primarily due to our Razorback drill pad service company that began generating revenue in 2013, partially offset by the sale of our Triad roof bolt manufacturing operation in September 2012, which generated revenue in 2012 that is not present in the 2013 comparable period.
Central Appalachia Overview of Results by Product. Additional information for the Central Appalachia segment detailing the types of coal produced and sold, premium high-vol metallurgical coal and steam coal, is presented below. Note that our Northern Appalachia and Rhino Western segments currently produce and sell only steam coal.
(In thousands, except per ton data and %) | | Year ended
December 31,
2013 | | Year ended
December 31,
2012 | | Increase
(Decrease) %* | |
Met coal tons sold | | 597.9 | | 467.8 | | 27.8 | % |
Steam coal tons sold | | 909.8 | | 1,288.3 | | (29.4 | )% |
Total tons sold † | | 1,507.7 | | 1,756.1 | | (14.1 | )% |
| | | | | | | |
Met coal revenue | | $ | 53,721 | | $ | 59,511 | | (9.7 | )% |
Steam coal revenue | | $ | 72,699 | | $ | 101,762 | | (28.6 | )% |
Total coal revenue † | | $ | 126,420 | | $ | 161,273 | | (21.6 | )% |
| | | | | | | |
Met coal revenues per ton | | $ | 89.86 | | $ | 127.21 | | (29.4 | )% |
Steam coal revenues per ton | | $ | 79.90 | | $ | 78.99 | | 1.2 | % |
Total coal revenues per ton † | | $ | 83.85 | | $ | 91.83 | | (8.7 | )% |
| | | | | | | |
Met coal tons produced | | 570.5 | | 468.3 | | 21.8 | % |
Steam coal tons produced | | 958.7 | | 1,336.2 | | (28.2 | )% |
Total tons produced † | | 1,529.2 | | 1,804.5 | | (15.3 | )% |
* Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.
† Excludes data for the Rhino Eastern mining complex located in West Virginia for which we serve as manager.
Costs and Expenses. The following table presents costs and expenses (including the cost of purchased coal) and cost of operations per ton by reportable segment for the years ended December 31, 2013 and 2012:
| | Year ended | | Year ended | | Increase/(Decrease) | | | |
Segment | | December 31, 2013 | | December 31, 2012 | | $ | | % * | |
| | (in millions, except per ton data and %) | |
Central Appalachia | | | | | | | | | |
| | | | | | | | | | | | |
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below) | | $ | 100.0 | | $ | 125.8 | | $ | (25.8 | ) | (20.5 | )% |
Freight and handling costs | | 0.3 | | 0.5 | | (0.2 | ) | (44.8 | )% |
Depreciation, depletion and amortization | | 24.2 | | 26.3 | | (2.1 | ) | (7.8 | )% |
Selling, general and administrative | | 18.5 | | 19.0 | | (0.5 | ) | (2.5 | )% |
Cost of operations per ton* | | $ | 66.33 | | $ | 71.62 | | $ | (5.29 | ) | (7.4 | )% |
| | | | | | | | | |
Northern Appalachia | | | | | | | | | |
| | | | | | | | | | | | |
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below) | | $ | 52.4 | | $ | 76.0 | | $ | (23.6 | ) | (31.0 | )% |
Freight and handling costs | | 1.0 | | 5.3 | | (4.3 | ) | (80.9 | )% |
Depreciation, depletion and amortization | | 8.1 | | 8.3 | | (0.2 | ) | (2.5 | )% |
Selling, general and administrative | | 0.3 | | 0.3 | | — | | (17.6 | )% |
Cost of operations per ton* | | $ | 42.79 | | $ | 40.54 | | $ | 2.25 | | 5.5 | % |
| | | | | | | | | |
Rhino Western | | | | | | | | | |
| | | | | | | | | | | | |
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below) | | $ | 30.7 | | $ | 27.5 | | $ | 3.2 | | 11.7 | % |
Freight and handling costs | | — | | — | | — | | n/a | |
Depreciation, depletion and amortization | | 5.5 | | 4.7 | | 0.8 | | 17.7 | % |
Selling, general and administrative | | 0.1 | | 0.1 | | — | | (5.4 | )% |
Cost of operations per ton* | | $ | 32.62 | | $ | 26.42 | | $ | 6.20 | | 23.5 | % |
| | | | | | | | | |
Other | | | | | | | | | |
| | | | | | | | | | | | |
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below) | | $ | 16.6 | | $ | 18.4 | | $ | (1.8 | ) | (10.1 | )% |
Freight and handling costs | | — | | — | | — | | n/a | |
Depreciation, depletion and amortization | | 1.8 | | 2.0 | | (0.2 | ) | (10.1 | )% |
Selling, general and administrative | | 0.9 | | 1.1 | | (0.2 | ) | (9.8 | )% |
Cost of operations per ton** | | n/a | | n/a | | n/a | | n/a | |
| | | | | | | | | |
Total | | | | | | | | | |
| | | | | | | | | | | | |
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below) | | $ | 199.7 | | $ | 247.7 | | $ | (48.0 | ) | (19.4 | )% |
Freight and handling costs | | 1.3 | | 5.8 | | (4.5 | ) | (77.8 | )% |
Depreciation, depletion and amortization | | 39.6 | | 41.3 | | (1.7 | ) | (4.0 | )% |
Selling, general and administrative | | 19.8 | | 20.5 | | (0.7 | ) | (3.1 | )% |
Cost of operations per ton* | | $ | 54.37 | | $ | 53.04 | | $ | 1.33 | | 2.5 | % |
* Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.
** Cost of operations for our Oil and Natural Gas segment do not relate to coal production. Cost of operations presented for our Other category includes costs incurred by our ancillary businesses. The activities performed by these ancillary businesses also do not directly relate to coal production. As a result, per ton measurements are not presented for our Oil and Natural Gas segment or our Other category.
Cost of Operations. Total cost of operations was $199.7 million for the year ended December 31, 2013 as compared to $247.7 million for the year ended December 31, 2012. Total cost of operations decreased primarily due to lower production at our Sands Hill complex in Northern Appalachia, which was in response to weak market conditions for coal from this complex, as well as decreased costs from purchased coal in Central Appalachia. Our cost of operations per ton was $54.37 for the year ended December 31, 2013; an increase of $1.33, or 2.5%, from the year ended December 31, 2012. The increase in the cost of operations on a per ton basis was primarily due to the sequence of mining at our Castle Valley mine in our Rhino Western segment where we performed more higher cost advance mining during 2013 compared to more lower cost retreat mining that was performed in 2012.
Our cost of operations for the Central Appalachia segment decreased by $25.8 million, or 20.5%, to $100.0 million for the year ended December 31, 2013 from $125.8 million for the year ended December 31, 2012. Our total cost of operations decreased for Central Appalachia primarily due to decreased costs from purchased coal in 2013 compared to 2012. Our cost of operations per ton decreased to $66.33 per ton for the year ended December 31, 2013 from $71.62 per ton for year ended December 31, 2012. The decrease in cost of operations per ton was primarily due to the fact that we idled a majority of the Central Appalachia operations in June and early July of 2012 in order to reduce higher than normal inventory levels, which resulted in a higher cost per ton figure for the 2012 period when compared to 2013.
In our Northern Appalachia segment, our cost of operations decreased by $23.6 million, or 31.0%, to $52.4 million for the year ended December 31, 2013 from $76.0 million for the year ended December 31, 2012. The decrease in cost of operations was primarily due to lower production at our Sands Hill complex in Northern Appalachia, which was in response to weak market conditions for coal from this complex. Our cost of operations per ton increased to $42.79 for the year ended December 31, 2013 from $40.54 for the year ended December 31, 2012, an increase of $2.25 per ton, or 5.5%. The increase in cost of operations per ton was primarily due to reducing production volumes at Sands Hill.
Cost of operations in our Rhino Western segment increased by $3.2 million, or 11.7%, to $30.7 million for the year ended December 31, 2013 from $27.5 million for the year ended December 31, 2012. Our cost of operations per ton increased to $32.62 for the year ended December 31, 2013 from $26.42 for the year ended December 31, 2012, an increase of $6.20 per ton, or 23.5%. The increases in cost of operations and cost of operations per ton were primarily due to the sequence of mining at our Castle Valley mine. During 2013, the mine was primarily advancing the sections which drove higher cost compared to the lower-cost retreat mining that was performed in 2012.
Cost of operations in our Other category decreased by $1.8 million to $16.6 million for the year ended December 31, 2013 compared to $18.4 million the year ended December 31, 2012. This decrease was primarily due to the sale of our Triad roof bolt manufacturing operation in September 2012, which incurred cost in 2012 that is not present in the 2013 comparable period.
Freight and Handling. Total freight and handling cost for the year ended December 31, 2013 decreased by $4.5 million, or 77.8%, to $1.3 million from $5.8 million for the year ended December 31, 2012. This decrease was primarily due to the decrease in tons of coal sold for 2013 compared to 2012 from our Sands Hill complex, which requires transportation by truck to customers’ locations.
Depreciation, Depletion and Amortization. Total DD&A expense for the year ended December 31, 2013 was $39.6 million as compared to $41.3 million for the year ended December 31, 2012.
For the year ended December 31, 2013, our depreciation cost was $31.5 million as compared to $32.7 million for the year ended December 31, 2012. This decrease is primarily due to a decrease in machinery and equipment depreciation from our Central Appalachia operations.
For the year ended December 31, 2013, our depletion cost was $5.4 million as compared to $5.8 million for the year ended December 31, 2012. This decrease is primarily attributable to fewer tons produced for the year ended December 31, 2013 compared to 2012 due to weakness in the met and steam coal markets.
For the year ended December 31, 2013, our amortization cost was relatively flat at $2.7 million as compared to $2.8 million for the year ended December 31, 2012.
Selling, General and Administrative. Selling, general and administrative (“SG&A”) expense for the year ended December 31, 2013 was $19.8 million as compared to $20.5 million for the year ended December 31, 2012. The decrease in SG&A expense is primarily attributable to a decrease in expenditures for legal fees and other professional fees.
Interest Expense. Interest expense for the year ended December 31, 2013 was $7.9 million as compared to $7.8 million for the year ended December 31, 2012, an increase of $0.1 million, or 1.7%. This increase was the result of an increase in the balance outstanding under our credit facility.
Eastern Met Supplemental Data. Operational and financial data for the Rhino Eastern joint venture in which we have a 51% membership interest and for which we serve as manager (referred to as the “Eastern Met” segment) is presented below. Our consolidated revenue and costs do not include any portion of the revenue or costs of Rhino Eastern since we account for this operation under the equity method. We only record our proportionate share of net income of Rhino Eastern as a single item in our financial statements, but we believe the presentation of these items for Rhino Eastern provides additional insight into how this operation contributes to our overall performance.
(In thousands, except per ton data and %) | | Year ended
December 31, 2013 | | Year ended
December 31, 2012 | | Increase
(Decrease) %* | |
Eastern Met 100% Basis | | | | | | | |
Coal revenues | | $ | 27,724 | | $ | 55,187 | | (49.8 | )% |
Total revenues | | $ | 27,853 | | $ | 55,221 | | (49.6 | )% |
Coal revenues per ton* | | $ | 111.27 | | $ | 185.98 | | (40.2 | )% |
Cost of operations | | $ | 31,543 | | $ | 36,728 | | (14.1 | )% |
Cost of operations per ton* | | $ | 126.60 | | $ | 123.77 | | 2.3 | % |
Depreciation, depletion and amortization | | $ | 1,949 | | $ | 2,098 | | (7.1 | )% |
Interest expense | | $ | 17 | | $ | 155 | | (89.3 | )% |
Net income (loss) | | $ | (8,369 | ) | $ | 11,937 | | (170.1 | )% |
Partnership’s portion of net income (loss) | | $ | (4,268 | ) | $ | 6,014 | | (171.0 | )% |
Tons produced | | 205.4 | | 337.1 | | (39.1 | )% |
Tons sold | | 249.2 | | 296.7 | | (16.0 | )% |
* Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.
The decrease in tons produced and sold for the year ended December 31, 2013 compared to 2012 was due to weakness in the met coal market, which resulted in a significant decrease in the market price for the quality of met coal that Rhino Eastern produces. The decrease in tons sold resulted in decreased revenue and net income for the year ended December 31, 2013 compared to the same period in 2012.
Net Income (Loss) from Continuing Operations. The following table presents net income (loss) from continuing operations by reportable segment for the years ended December 31, 2013 and 2012:
| | Year ended | | Year ended | | Increase | |
Segment | | December 31, 2013 | | December 31, 2012 | | (Decrease) | |
| | (in millions) | |
Central Appalachia | | $ | (7.1 | ) | $ | 3.6 | | $ | (10.7 | ) |
Northern Appalachia | | 26.1 | | 29.6 | | (3.5 | ) |
Rhino Western | | (2.4 | ) | 5.7 | | (8.1 | ) |
Eastern Met * | | (4.3 | ) | 6.0 | | (10.3 | ) |
Other | | (4.2 | ) | (5.5 | ) | 1.3 | |
Total | | $ | 8.1 | | $ | 39.4 | | $ | (31.3 | ) |
* Includes our 51% equity interest in the results of the Rhino Eastern joint venture, which owns the Rhino Eastern mining complex located in West Virginia and for which we serve as manager.
For the year ended December 31, 2013, total net income from continuing operations was $8.1 million compared to $39.4 million for the year ended December 31, 2012 as decreases in costs and expenses were offset by decreases in coal revenues, including lower royalty revenue from our coal leasing business, as well as lower results from our Rhino Eastern joint venture. For the year ended December 31, 2013, our net income from continuing operations was positively impacted by $10.5 million from the sale of our 20% royalty interest on our Utica Shale property. Net income from continuing operations was positively impacted by $7.4 million received as a lease bonus payment in 2012 related to acreage we own in the Utica Shale region of eastern Ohio, which had relatively immaterial costs associated with the transaction. The Utica Shale transactions discussed above related to property we previously owned and was not part of the Utica Shale sale transaction with Gulfport in March 2014, which is why these transactions are included in continuing operations.
For our Central Appalachia segment, we generated a net loss from continuing operations of approximately $7.1 million for the year ended December 31, 2013, a decrease of $10.7 million, as compared to the year ended December 31, 2012. The year to year decrease was primarily due to a decrease in tons sold, which decreased revenue, and an approximate $0.9 million charge incurred for the write-off of a continuous miner that was destroyed at one of our underground Central Appalachia mines.
Net income from continuing operations in our Northern Appalachia segment decreased by $3.5 million to $26.1 million for the year ended December 31, 2013, from $29.6 million for the year ended December 31, 2012. Net income from continuing operations in our Northern Appalachia segment was impacted from the $10.5 million received from the sale of our 20% royalty interest on our Utica Shale property in the year ended December 31, 2013 as compared to approximately $7.4 million of lease bonus payments that we received on our Utica Shale property in the year ended December 31, 2012. The increase period to period due to the Utica Shale payments received was partially offset by decreased tons of coal sold from our Sands Hill complex due to weakness in the steam coal market. The Utica Shale transactions discussed above related to property we previously owned and was not part of the Utica Shale sale transaction with Gulfport in March 2014, which is why these transactions are included in continuing operations.
Net income from continuing operations in our Rhino Western segment decreased by $8.1 million to a loss of $2.4 million for the year ended December 31, 2013, compared to net income from continuing operations of $5.7 million for the year ended December 31, 2012. This decrease was primarily the result of an increase in cost of operations at our Castle Valley operation due to the sequence of mining discussed earlier, as well as decreased revenue from lower tons sold at Castle Valley due to fewer spot sales. Net income from continuing operations for our Rhino Western segment was also impacted from an asset impairment loss of approximately $1.7 million due to the permanently idling of our McClane Canyon mine at the end of 2013.
Our Eastern Met segment recorded a net loss from continuing operations of $4.3 million for the year ended December 31, 2013, a decrease of $10.3 million from net income from continuing operations of $6.0 million for the year ended December 31, 2012, as weakness in the met coal market caused a decrease in the number of tons sold and lower prices for tons sold.
For the Other category, we had a net loss from continuing operations of $4.2 million for the year ended December 31, 2013, a benefit of $1.3 million as compared to a net loss from continuing operations of $5.5 million for the year ended December 31, 2012. The improvement was primarily due to decreased costs in 2013 compared to 2012 in our ancillary businesses that support our coal operations.
Adjusted EBITDA from Continuing Operations. The following table presents Adjusted EBITDA from continuing operations by reportable segment for the years ended December 31, 2013 and 2012:
| | Year ended | | Year ended | | Increase | |
Segment | | December 31, 2013 | | December 31, 2012 | | (Decrease) | |
| | (in millions) | |
Central Appalachia | | $ | 21.9 | | $ | 34.3 | | $ | (12.4 | ) |
Northern Appalachia | | 35.0 | | 38.7 | | (3.7 | ) |
Rhino Western | | 5.4 | | 11.1 | | (5.7 | ) |
Eastern Met * | | (3.3 | ) | 7.1 | | (10.4 | ) |
Other | | 0.2 | | (1.6 | ) | 1.8 | |
Total Adjusted EBITDA | | $ | 59.2 | | $ | 89.6 | | $ | (30.4 | ) |
* Includes our 51% equity interest in the results of the Rhino Eastern joint venture, which owns the Rhino Eastern mining complex located in West Virginia and for which we serve as manager.
Total Adjusted EBITDA from continuing operations for the year ended December 31, 2013 was $59.2 million, a decrease of $30.4 million from $89.6 million for the year ended December 31, 2012. Adjusted EBITDA from continuing operations decreased primarily as a result of a decrease in net income from continuing operations, as described previously. Please read “—Reconciliation of Adjusted EBITDA to Net Income by Segment” for reconciliations of Adjusted EBITDA from continuing operations to net income from continuing operations on a segment basis.
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
Summary. For the year ended December 31, 2012, our total revenues decreased to $351.7 million from $367.2 million for the year ended December 31, 2011. We sold 4.7 million tons of coal for the year ended December 31, 2012, which is 0.2 million tons less, or a 4.2% decrease, than the 4.9 million tons of coal sold for the year ended December 31, 2011. This decrease in tons sold was the result of weak demand in the met and steam coal markets, which resulted in lower coal revenues for 2012 compared to 2011. We believe the weak demand in the steam coal markets was primarily driven by an unseasonably mild winter along with an over-supply of low priced natural gas, both of which resulted in an increase of coal inventory supplies at electric utilities and fewer tons of steam coal being utilized in electricity generation. We believe the weak demand in the met coal markets was primarily driven by a decrease in world-wide steel production due to economic weakness in China and Europe.
For the year ended December 31, 2012, our coal inventories increased by approximately 29,000 tons from the year ended December 31, 2011 due to weak demand in the steam and met coal markets.
Net income from continuing operations was $39.4 million for the year ended December 31, 2012 compared to $37.3 million for the year ended December 31, 2011. Adjusted EBITDA from continuing operations increased to $89.6 million for the year ended December 31, 2012, from $81.2 million for the year ended December 31, 2011. Net income from continuing operations and Adjusted EBITDA from continuing operations were positively impacted by the $7.4 million lease bonus payments received in 2012 related to our Utica Shale acreage, which had relatively immaterial costs associated with the transaction. The Utica Shale transaction discussed above related to property we previously owned and was not part of the Utica Shale sale transaction with Gulfport in March 2014, which is why this transaction is included in continuing operations. Net income from continuing operations and Adjusted EBITDA from continuing operations were also positively impacted in 2012 due to $6.0 million of income from our Rhino Eastern joint venture compared to income of $3.0 million for 2011, each of which represents our proportionate share of income from the Rhino Eastern joint venture in which we have a 51% membership interest and for which we serve as manager.
Including the income from discontinued operations of approximately $0.1 million from our Utica Shale activities, our total net income for the year ended December 31, 2012 was approximately $39.5 million and our total Adjusted EBITDA was $89.8 million when our discontinued operations items are included. There was no income from discontinued operations for the year ended December 31, 2011. The year to year increase in total net income and Adjusted EBITDA are due to the same factors discussed above for the year to year increase in net income from continuing operations and Adjusted EBITDA from continuing operations.
Tons Sold. The following table presents tons of coal sold by reportable segment for the years ended December 31, 2012 and 2011:
| | | | | | Increase | | | |
| | Year Ended | | Year Ended | | (Decrease) | | | |
Segment | | December 31, 2012 | | December 31, 2011 | | Tons | | % * | |
| | (in thousands, except %) | |
Central Appalachia | | 1,756.1 | | 2,308.0 | | (551.9 | ) | (23.9 | )% |
Northern Appalachia | | 1,875.1 | | 2,061.5 | | (186.4 | ) | (9.0 | )% |
Rhino Western | | 1,038.9 | | 506.6 | | 532.3 | | 105.1 | % |
Total *† | | 4,670.1 | | 4,876.1 | | (206.0 | ) | (4.2 | )% |
* Calculated percentages and the rounded totals presented are based upon on actual whole ton amounts and not the rounded amounts presented in this table.
† Excludes tons sold by the Rhino Eastern joint venture, which owns the Rhino Eastern mining complex located in West Virginia and for which we serve as manager.
We sold approximately 4.7 million tons of coal in the year ended December 31, 2012 as compared to approximately 4.9 million tons sold for the year ended December 31, 2011. This decrease in tons sold was primarily due to weakness in the met and steam coal markets, primarily in Central Appalachia, partially offset by increased sales at our Castle Valley operation in Utah. Tons of coal sold in our Central Appalachia segment decreased by approximately 0.5 million, or 23.9%, to approximately 1.8 million tons for the year ended December 31, 2012 from approximately 2.3 million tons for the year ended December 31, 2011. The decrease in total tons sold year-to-year in Central Appalachia was primarily due to weakness in the met and steam coal markets. For our Northern Appalachia segment, tons of coal sold decreased by approximately 0.2 million, or 9.0%, to approximately 1.9 million tons for the year ended December 31, 2012 from approximately 2.1 million tons for the year ended December 31, 2011. The decrease in total tons sold year-to-year in Northern Appalachia was primarily due to weakness in the steam coal markets. Coal sales from our Rhino Western segment increased by approximately 0.5 million, or 105.1%, to approximately 1.0 million tons for the year ended December 31, 2012 from approximately 0.5 million tons for the year ended December 31, 2011 as this operation was still being prepared for full operation in 2011 compared to operating at a greater capacity in 2012.
Revenues. The following table presents revenues and coal revenues per ton by reportable segment for the years ended December 31, 2012 and 2011:
| | Year ended | | Year ended | | Increase/(Decrease) | | | |
Segment | | December 31, 2012 | | December 31, 2011 | | $ | | % * | |
| | (in millions, except per ton data and %) | |
Central Appalachia | | | | | | | | | |
Coal revenues | | $ | 161.3 | | $ | 202.9 | | $ | (41.6 | ) | (20.5 | )% |
Freight and handling revenues | | — | | — | | — | | n/a | |
Other revenues | | 22.1 | | 16.3 | | 5.8 | | 35.3 | % |
Total revenues | | $ | 183.4 | | $ | 219.2 | | $ | (35.8 | ) | (16.4 | )% |
Coal revenues per ton* | | $ | 91.83 | | $ | 87.92 | | $ | 3.91 | | 4.4 | % |
Northern Appalachia | | | | | | | | | |
Coal revenues | | $ | 102.9 | | $ | 109.3 | | $ | (6.4 | ) | (5.8 | )% |
Freight and handling revenues | | 6.3 | | 5.7 | | 0.6 | | 10.6 | % |
Other revenues | | 12.8 | | 5.0 | | 7.8 | | 158.4 | % |
Total revenues | | $ | 122.0 | | $ | 120.0 | | $ | 2.0 | | 1.7 | % |
Coal revenues per ton* | | $ | 54.87 | | $ | 53.00 | | $ | 1.87 | | 3.5 | % |
Rhino Western | | | | | | | | | |
Coal revenues | | $ | 40.4 | | $ | 21.7 | | $ | 18.7 | | 86.4 | % |
Freight and handling revenues | | — | | — | | — | | n/a | |
Other revenues | | 0.3 | | — | | 0.3 | | n/a | |
Total revenues | | $ | 40.7 | | $ | 21.7 | | $ | 19.0 | | 87.6 | % |
Coal revenues per ton* | | $ | 38.89 | | $ | 42.78 | | $ | (3.89 | ) | (9.1 | )% |
Other** | | | | | | | | | |
Coal revenues | | n/a | | n/a | | n/a | | n/a | |
Freight and handling revenues | | n/a | | n/a | | n/a | | n/a | |
Other revenues | | $ | 5.6 | | $ | 6.3 | | $ | (0.7 | ) | (10.2 | )% |
Total revenues | | $ | 5.6 | | $ | 6.3 | | $ | (0.7 | ) | (10.2 | )% |
Coal revenues per ton* | | n/a | | n/a | | n/a | | n/a | |
Total | | | | | | | | | |
Coal revenues | | $ | 304.6 | | $ | 333.9 | | $ | (29.3 | ) | (8.8 | )% |
Freight and handling revenues | | 6.3 | | 5.7 | | 0.6 | | 10.6 | % |
Other revenues | | 40.8 | | 27.6 | | 13.2 | | 47.9 | % |
Total revenues | | $ | 351.7 | | $ | 367.2 | | $ | (15.5 | ) | (4.2 | )% |
Coal revenues per ton* | | $ | 65.22 | | $ | 68.47 | | $ | (3.25 | ) | (4.8 | )% |
* Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.
** The Oil and Natural Gas segment does not relate to coal production. The Other category includes results for our ancillary businesses. The activities performed by these ancillary businesses also do not directly relate to coal production. As a result, coal revenues and coal revenues per ton are not presented for the Oil and Natural Gas segment or the Other category.
Our total revenues for the year ended December 31, 2012 decreased by $15.5 million, or 4.2%, to $351.7 million from $367.2 million for the year ended December 31, 2011. The decrease in total revenues was due to lower coal revenues resulting primarily from weakness in the met and steam coal markets, which was partially offset by an increase in other revenues that primarily resulted from the $7.4 million lease bonus received for acreage owned in the Utica Shale region. Our other revenue also increased in 2012 due to a full year of revenue from our coal leasing business compared to only a partial year of revenue from our coal leasing operations in 2011 since we purchased this business in June 2011. Coal revenues per ton were $65.22 for the year ended December 31, 2012, a decrease of $3.25, or 4.8%, from $68.47 per ton for the year ended December 31, 2011. This decrease in coal revenues per ton was primarily the result of a higher proportion of lower priced coal from our Rhino Western operations of our total tons of coal sold.
For our Central Appalachia segment, coal revenues decreased by $41.6 million, or 20.5%, to $161.3 million for the year ended December 31, 2012 from $202.9 million for the year ended December 31, 2011 due to weakness in the met and steam coal markets, which resulted in fewer tons sold. Coal revenues per ton for our Central Appalachia segment increased by $3.91, or 4.4%, to $91.83 per ton for the year ended December 31, 2012 as compared to $87.92 for the year ended December 31, 2011, primarily due to higher contracted prices, primarily related to metallurgical coal sold. Other revenues increased for our Central Appalachia segment primarily due to coal royalty revenue from our coal leasing operations.
For our Northern Appalachia segment, coal revenues were $102.9 million for the year ended December 31, 2012, a decrease of $6.4 million, or 5.8%, from $109.3 million for the year ended December 31, 2011. This decrease was due to weakness in the steam coal market, which resulted in fewer tons sold. Coal revenues per ton for our Northern Appalachia segment increased by $1.87, or 3.5%, to $54.87 per ton for the year ended December 31, 2012 as compared to $53.00 per ton for the year ended December 31, 2011. This increase was primarily due to higher contracted prices for steam coal. Other revenues increased for our Northern Appalachia segment primarily due to the $7.4 million lease bonus received for acreage owned in the Utica Shale region. The Utica Shale transaction discussed above related to property we previously owned and was not part of the Utica Shale sale transaction with Gulfport in March 2014, which is why this transaction is included in continuing operations.
For our Rhino Western segment, coal revenues increased by $18.7 million, or 86.4%, to $40.4 million for the year ended December 31, 2012 from $21.7 million for the year ended December 31, 2011 due to an increase in tons sold for coal produced at our Castle Valley mine. Coal revenues per ton for our Rhino Western segment were $38.89 for the year ended December 31, 2012, a decrease of $3.89, or 9.1%, from $42.78 for the year ended December 31, 2011. The decrease in coal revenues per ton was due to lower market prices for coal produced at our Castle Valley mine.
Other revenues for our Other category decreased by $0.7 million for the year ended December 31, 2012 from the year ended December 31, 2011, which was primarily due to a decrease in revenue from our Triad roof bolt operations that were sold in September 2012.
Central Appalachia Overview of Results by Product. Additional information for the Central Appalachia segment detailing the types of coal produced and sold, premium high-vol metallurgical coal and steam coal, is presented below. Note that our Northern Appalachia and Rhino Western segments currently produce and sell only steam coal.
(In thousands, except per ton data and %) | | Year ended
December 31,
2012 | | Year ended
December 31,
2011 | | Increase
(Decrease) %* | |
Met coal tons sold | | 467.8 | | 654.6 | | (28.5 | )% |
Steam coal tons sold | | 1,288.3 | | 1,653.4 | | (22.1 | )% |
Total tons sold † | | 1,756.1 | | 2,308.0 | | (23.9 | )% |
| | | | | | | |
Met coal revenue | | $ | 59,511 | | $ | 79,227 | | (24.9 | )% |
Steam coal revenue | | $ | 101,762 | | $ | 123,706 | | (17.7 | )% |
Total coal revenue † | | $ | 161,273 | | $ | 202,933 | | (20.5 | )% |
| | | | | | | |
Met coal revenues per ton | | $ | 127.21 | | $ | 121.04 | | 5.1 | % |
Steam coal revenues per ton | | $ | 78.99 | | $ | 74.82 | | 5.6 | % |
Total coal revenues per ton † | | $ | 91.83 | | $ | 87.92 | | 4.4 | % |
| | | | | | | |
Met coal tons produced | | 468.3 | | 660.5 | | (29.1 | )% |
Steam coal tons produced | | 1,336.2 | | 1,573.5 | | (15.1 | )% |
Total tons produced † | | 1,804.5 | | 2,234.0 | | (19.2 | )% |
* Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.
† Excludes data for the Rhino Eastern mining complex located in West Virginia for which we serve as manager.
Costs and Expenses. The following table presents costs and expenses (including the cost of purchased coal) and cost of operations per ton by reportable segment for the years ended December 31, 2012 and 2011:
| | Year ended | | Year ended | | Increase/(Decrease) | | | |
Segment | | December 31, 2012 | | December 31, 2011 | | $ | | % * | |
| | (in millions, except per ton data and %) | |
Central Appalachia | | | | | | | | | |
| | | | | | | | | |
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below) | | $ | 125.8 | | $ | 154.7 | | $ | (28.9 | ) | (18.6 | )% |
Freight and handling costs | | 0.5 | | — | | 0.5 | | n/a | |
Depreciation, depletion and amortization | | 26.3 | | 22.1 | | 4.2 | | 18.6 | % |
Selling, general and administrative | | 19.0 | | 20.2 | | (1.2 | ) | (6.1 | )% |
Cost of operations per ton* | | $ | 71.62 | | $ | 66.97 | | $ | 4.65 | | 6.9 | % |
| | | | | | | | | |
Northern Appalachia | | | | | | | | | |
| | | | | | | | | |
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below) | | $ | 76.0 | | $ | 75.1 | | $ | 0.9 | | 1.2 | % |
Freight and handling costs | | 5.3 | | 4.3 | | 1.0 | | 23.3 | % |
Depreciation, depletion and amortization | | 8.3 | | 8.1 | | 0.2 | | 2.2 | % |
Selling, general and administrative | | 0.3 | | 0.4 | | (0.1 | ) | (13.4 | )% |
Cost of operations per ton* | | $ | 40.54 | | $ | 36.45 | | $ | 4.09 | | 11.2 | % |
| | | | | | | | | |
Rhino Western | | | | | | | | | |
| | | | | | | | | |
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below) | | $ | 27.5 | | $ | 17.9 | | $ | 9.6 | | 53.0 | % |
Freight and handling costs | | — | | — | | — | | n/a | |
Depreciation, depletion and amortization | | 4.7 | | 3.1 | | 1.6 | | 52.2 | % |
Selling, general and administrative | | 0.1 | | 0.1 | | — | | 2.9 | % |
Cost of operations per ton* | | $ | 26.42 | | $ | 35.42 | | $ | (9.00 | ) | (25.4 | )% |
| | | | | | | | | |
Other | | | | | | | | | |
| | | | | | | | | |
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below) | | $ | 18.4 | | $ | 20.0 | | $ | (1.6 | ) | (7.4 | )% |
Freight and handling costs | | — | | — | | — | | n/a | |
Depreciation, depletion and amortization | | 2.0 | | 3.0 | | (1.0 | ) | (31.1 | )% |
Selling, general and administrative | | 1.1 | | 1.1 | | — | | (8.2 | )% |
Cost of operations per ton** | | n/a | | n/a | | n/a | | n/a | |
| | | | | | | | | |
Total | | | | | | | | | |
| | | | | | | | | |
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below) | | $ | 247.7 | | $ | 267.7 | | $ | (20.0 | ) | (7.4 | )% |
Freight and handling costs | | 5.8 | | 4.3 | | 1.5 | | 34.8 | % |
Depreciation, depletion and amortization | | 41.3 | | 36.3 | | 5.0 | | 13.6 | % |
Selling, general and administrative | | 20.5 | | 21.8 | | (1.3 | ) | (6.3 | )% |
Cost of operations per ton* | | $ | 53.04 | | $ | 54.88 | | $ | (1.84 | ) | (3.3 | )% |
* Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.
** Cost of operations for our Oil and Natural Gas segment do not relate to coal production. Cost of operations presented for our Other category includes costs incurred by our ancillary businesses. The activities performed by these ancillary businesses also do not directly relate to coal production. As a result, per ton measurements are not presented for our Oil and Natural Gas segment or our Other category.
Cost of Operations. Total cost of operations was $247.7 million for the year ended December 31, 2012 as compared to $267.7 million for the year ended December 31, 2011. The decrease in the cost of operations was primarily due to decreased production due to weakness in the met and steam coal markets, including the idling of a majority of our Central Appalachia operations in June 2012. Our cost of operations per ton was $53.04 for the year ended December 31, 2012; a decrease of $1.84, or 3.3%, from the year ended December 31, 2011. The decrease in the cost of operations on a per ton basis was primarily due to a higher mix of lower cost tons from our Castle Valley mine.
Our cost of operations for the Central Appalachia segment decreased by $28.9 million, or 18.6%, to $125.8 million for the year ended December 31, 2012 from $154.7 million for the year ended December 31, 2011. The decrease in total cost of operations was primarily due to decreased production in response to weakness in the met and steam coal markets, including the temporary idling of a majority of our Central Appalachia operations in June 2012. Our cost of operations per ton increased to $71.62 per ton for the year ended December 31, 2012 from $66.97 per ton for year ended December 31, 2011. Cost of operations per ton increased since a portion of our costs are fixed in nature and these fixed costs were spread over a smaller number of tons sold in 2012.
In our Northern Appalachia segment, our cost of operations increased by $0.9 million, or 1.2%, to $76.0 million for the year ended December 31, 2012 from $75.1 million for the year ended December 31, 2011. Our cost of operations per ton increased to $40.54 for the year ended December 31, 2012 from $36.45 for the year ended December 31, 2011, an increase of $4.09 per ton, or 11.2%. The increases in cost of operations and cost of operations per ton were primarily due to geology issues of mining thinner coal seams at our Hopedale mine and an equipment issue that resulted in the need to replace a mining shovel at one of our Sands Hill surface mines in the second quarter of 2012.
Cost of operations in our Rhino Western segment increased by $9.6 million, or 53.0%, to $27.5 million for the year ended December 31, 2012 from $17.9 million for the year ended December 31, 2011. Our cost of operations per ton decreased to $26.42 for the year ended December 31, 2012 from $35.42 for the year ended December 31, 2011, a decrease of $9.00 per ton, or 25.4%. The increase in cost of operations was primarily due to increased production at our Castle Valley mine. Cost of operations per ton decreased primarily due to our Castle Valley mine being at full production in 2012 compared to costs incurred in 2011 associated with preparing our Castle Valley mine to begin production that had a smaller amount of tons sold.
Cost of operations in our Other category decreased by $1.6 million for the year ended December 31, 2012 as compared to the year ended December 31, 2011. This decrease was primarily as a result of the sale of our Triad roof bolt operations in September 2012.
Freight and Handling. Total freight and handling cost for the year ended December 31, 2012 increased by $1.5 million, or 34.8%, to $5.8 million from $4.3 million for the year ended December 31, 2011. This increase was primarily due to an increase in the tons of limestone sold for 2012 as compared to 2011, along with increased coal freight and handling costs in Central Appalachia due to a new customer contract that required coal to be transported by truck to the customer’s location.
Depreciation, Depletion and Amortization. Total DD&A expense for the year ended December 31, 2012 was $41.3 million as compared to $36.3 million for the year ended December 31, 2011.
For the year ended December 31, 2012, our depreciation cost was $32.7 million as compared to $26.5 million for the year ended December 31, 2011. The increase in depreciation cost in 2012 was primarily due to an increase in machinery and equipment, including a new high-wall miner purchased in Central Appalachia.
For the year ended December 31, 2012, our depletion cost was $5.8 million as compared to $5.1 million for the year ended December 31, 2011. The increase in depletion cost in 2012 is primarily attributable to depletion expense incurred at
our coal leasing operations that was not present in the entire 2011 comparable period since our coal leasing business was acquired in June 2011.
For the year ended December 31, 2012, our amortization cost was $2.8 million as compared to $4.7 million for the year ended December 31, 2011. This decrease is primarily attributable to changes in the amortization for both mine development costs and asset retirement costs based on revisions to reserve valuations and useful lives.
Selling, General and Administrative. Selling, general and administrative (“SG&A”) expense for the year ended December 31, 2012 was $20.5 million as compared to $21.8 million for the year ended December 31, 2011. The decrease in SG&A expense is primarily attributable to a decrease in expenditures for legal fees and other professional fees.
Interest Expense. Interest expense for the year ended December 31, 2012 was $7.8 million as compared to $6.1 million for the year ended December 31, 2011, an increase of $1.7 million, or 28.1%. This increase was the result of an increase in the balance outstanding under our credit facility.
Eastern Met Supplemental Data. Operational and financial data for the Rhino Eastern joint venture in which we have a 51% membership interest and for which we serve as manager (referred to as the “Eastern Met” segment) is presented below. Our consolidated revenue and costs do not include any portion of the revenue or costs of Rhino Eastern since we account for this operation under the equity method. We only record our proportionate share of net income of Rhino Eastern as a single item in our financial statements, but we believe the presentation of these items for Rhino Eastern provides additional insight into how this operation contributes to our overall performance.
(In thousands, except per ton data and %) | | Year ended
December 31, 2012 | | Year ended
December 31, 2011 | | Increase
(Decrease) %* | |
Eastern Met 100% Basis | | | | | | | |
Coal revenues | | $ | 55,187 | | $ | 49,999 | | 10.4 | % |
Total revenues | | $ | 55,221 | | $ | 50,073 | | 10.3 | % |
Coal revenues per ton* | | $ | 185.98 | | $ | 198.97 | | (6.5 | )% |
Cost of operations | | $ | 36,728 | | $ | 38,412 | | (4.4 | )% |
Cost of operations per ton* | | $ | 123.77 | | $ | 152.86 | | (19.0 | )% |
Depreciation, depletion and amortization | | $ | 2,098 | | $ | 2,959 | | (29.1 | )% |
Interest expense | | $ | 155 | | $ | 52 | | 200.5 | % |
Net income (loss) | | $ | 11,937 | | $ | 5,715 | | 108.9 | % |
Partnership’s portion of net income (loss) | | $ | 6,014 | | $ | 2,988 | | 101.3 | % |
Tons produced | | 337.1 | | 266.2 | | 26.6 | % |
Tons sold | | 296.7 | | 251.3 | | 18.1 | % |
* Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.
Rhino Eastern’s Eagle #2 mine began production in the third quarter of 2011, which was replaced by Rhino Eastern’s Eagle #3 mine that began production in the third quarter of 2012 due to adverse conditions in the coal seams at the Eagle #2 mine. The year-to-date operation of the Eagle #2 mine resulted in an increase in tons produced and sold for 2012 compared to 2011. The increase in tons sold resulted in increased revenue and net income for 2012 compared to 2011.
Net Income (Loss) from Continuing Operations. The following table presents net income (loss) from continuing operations by reportable segment for the years ended December 31, 2012 and 2011:
| | Year ended | | Year ended | | Increase | |
Segment | | December 31, 2012 | | December 31, 2011 | | (Decrease) | |
| | (in millions) | |
Central Appalachia | | $ | 3.6 | | $ | 16.5 | | $ | (12.9 | ) |
Northern Appalachia | | 29.6 | | 27.4 | | 2.2 | |
Rhino Western | | 5.7 | | (2.6 | ) | 8.3 | |
Eastern Met * | | 6.0 | | 3.0 | | 3.0 | |
Other | | (5.5 | ) | (7.0 | ) | 1.5 | |
Total | | $ | 39.4 | | $ | 37.3 | | $ | 2.1 | |
* Includes our 51% equity interest in the results of the Rhino Eastern joint venture, which owns the Rhino Eastern mining complex located in West Virginia and for which we serve as manager.
For the year ended December 31, 2012, total net income from continuing operations was $39.4 million compared to $37.3 million for the year ended December 31, 2011. Net income from continuing operations was positively impacted by $7.4 million received as a lease bonus payment in 2012 related to acreage we own in the Utica Shale region of eastern Ohio, which had relatively immaterial costs associated with the transaction. The Utica Shale transactions discussed above related to property we previously owned and was not part of the Utica Shale sale transaction with Gulfport in March 2014, which is why these transactions are included in continuing operations.
For our Central Appalachia segment, net income from continuing operations decreased to $3.6 million for the year ended December 31, 2012, a decrease of $12.9 million, as compared to the year ended December 31, 2011. This decrease was primarily due to weakness in the steam and met coal markets that resulted in fewer tons sold.
Net income from continuing operations in our Northern Appalachia segment increased by $2.2 million to $29.6 million for the year ended December 31, 2012, from $27.4 million for the year ended December 31, 2011. This increase was primarily the result of the $7.4 million lease bonus payment partially offset by a decrease in tons of coal sold due to weakness in the steam coal markets.
Net income from continuing operations in our Rhino Western segment increased by $8.3 million to income from continuing operations of $5.7 million for the year ended December 31, 2012, compared to a loss from continuing operations of $2.6 million for the year ended December 31, 2011. This increase was primarily the result of more tons sold from the Castle Valley mine.
Our Eastern Met segment recorded net income from continuing operations of $6.0 million for the year ended December 31, 2012, an increase of $3.0 million from $3.0 million recorded for the year ended December 31, 2011.
For the Other category, we had a net loss from continuing operations of $5.5 million for the year ended December 31, 2012, a benefit of $1.5 million as compared to a net loss from continuing operations of $7.0 million for the year ended December 31, 2011.
Adjusted EBITDA from Continuing Operations . The following table presents Adjusted EBITDA from continuing operations by reportable segment for the years ended December 31, 2012 and 2011:
| | Year ended | | Year ended | | Increase | |
Segment | | December 31, 2012 | | December 31, 2011 | | (Decrease) | |
| | (in millions) | |
Central Appalachia | | $ | 34.3 | | $ | 41.6 | | $ | (7.3 | ) |
Northern Appalachia | | 38.7 | | 36.3 | | 2.4 | |
Rhino Western | | 11.1 | | 1.0 | | 10.1 | |
Eastern Met * | | 7.1 | | 4.5 | | 2.6 | |
Other | | (1.6 | ) | (2.2 | ) | 0.6 | |
Total Adjusted EBITDA | | $ | 89.6 | | $ | 81.2 | | $ | 8.4 | |
* Includes our 51% equity interest in the results of the Rhino Eastern joint venture, which owns the Rhino Eastern mining complex located in West Virginia and for which we serve as manager.
Total Adjusted EBITDA from continuing operations for the year ended December 31, 2012 was $89.6 million, an increase of $8.4 million from $81.2 million for the year ended December 31, 2011, primarily due to an increase in net income from continuing operations, along with higher DD&A and interest expense. Please read “—Reconciliation of Adjusted EBITDA to Net Income by Segment” for reconciliations of Adjusted EBITDA to net income on a segment basis.
Reconciliation of Adjusted EBITDA to Net Income by Segment
The following tables present reconciliations of Adjusted EBITDA to net income on a segment basis for each of the periods indicated. We believe the presentation of Adjusted EBITDA that includes the proportionate share of DD&A and interest expense for our Rhino Eastern joint venture is appropriate since our portion of Rhino Eastern’s net income that is recognized as a single line item in our financial statements is affected by these expense items. Since we do not reflect these proportionate expense items of DD&A and interest expense in our consolidated financial statements, we believe that the adjustment for these expense items in the Adjusted EBITDA calculation is more representative of how we review our results and also provides investors with additional information that they can use to evaluate our results. Adjusted EBITDA also excludes the effect of certain non-recurring items.
| | Central | | Northern | | Rhino | | Eastern | | | | | |
Year ended December 31, 2013 | | Appalachia | | Appalachia | | Western | | Met* | | Other | | Total | |
| | (in millions) | |
Net (loss)/income from continuing operations | | $ | (7.1 | ) | $ | 26.1 | | $ | (2.4 | ) | $ | (4.3 | ) | $ | (4.2 | ) | $ | 8.1 | |
Plus: | | | | | | | | | | | | | |
DD&A | | 24.2 | | 8.1 | | 5.5 | | — | | 1.8 | | 39.6 | |
Interest expense | | 3.9 | | 0.8 | | 0.6 | | — | | 2.6 | | 7.9 | |
EBITDA from continuing operations†** | | $ | 21.0 | | $ | 35.0 | | $ | 3.7 | | $ | (4.3 | ) | $ | 0.2 | | $ | 55.6 | |
Plus: Rhino Eastern DD&A-51% | | — | | — | | — | | 1.0 | | — | | 1.0 | |
Plus: Rhino Eastern interest expense-51% | | — | | — | | — | | — | | — | | — | |
Plus: Non-cash write-off of mining equipment and asset impairment*** | | 0.9 | | — | | 1.7 | | — | | — | | 2.6 | |
Adjusted EBITDA from continuing operations† | | 21.9 | | 35.0 | | 5.4 | | (3.3 | ) | 0.2 | | 59.2 | |
Net income from discontinued operations | | — | | — | | — | | — | | — | | 1.3 | |
DD&A included in net income from discontinued operations | | — | | — | | — | | — | | — | | 3.0 | |
Adjusted EBITDA † | | $ | 21.9 | | $ | 35.0 | | $ | 5.4 | | $ | (3.3 | ) | $ | 0.2 | | $ | 63.5 | |
| | Central | | Northern | | Rhino | | Eastern | | | | | |
Year ended December 31, 2012 | | Appalachia | | Appalachia | | Western | | Met* | | Other | | Total | |
| | (in millions) | |
Net income/(loss) from continuing operations | | $ | 3.6 | | $ | 29.6 | | $ | 5.7 | | $ | 6.0 | | $ | (5.5 | ) | $ | 39.4 | |
Plus: | | | | | | | | | | | | | |
DD&A | | 26.3 | | 8.3 | | 4.7 | | — | | 2.0 | | 41.3 | |
Interest expense | | 4.4 | | 0.8 | | 0.7 | | — | | 1.9 | | 7.8 | |
EBITDA from continuing operations†** | | $ | 34.3 | | $ | 38.7 | | $ | 11.1 | | $ | 6.0 | | $ | (1.6 | ) | $ | 88.5 | |
Plus: Rhino Eastern DD&A-51% | | — | | — | | — | | 1.0 | | — | | 1.0 | |
Plus: Rhino Eastern interest expense-51% | | — | | — | | — | | 0.1 | | — | | 0.1 | |
Adjusted EBITDA from continuing operations† | | 34.3 | | 38.7 | | 11.1 | | 7.1 | | (1.6 | ) | 89.6 | |
Net income from discontinued operations | | — | | — | | — | | — | | — | | 0.1 | |
DD&A included in net income from discontinued operations | | — | | — | | — | | — | | — | | 0.1 | |
Adjusted EBITDA † | | $ | 34.3 | | $ | 38.7 | | $ | 11.1 | | $ | 7.1 | | $ | (1.6 | ) | $ | 89.8 | |
| | Central | | Northern | | Rhino | | Eastern | | | | | |
Year ended December 31, 2011 | | Appalachia | | Appalachia | | Western | | Met* | | Other | | Total** | |
| | (in millions) | |
Net income/(loss) from continuing operations | | $ | 16.5 | | $ | 27.4 | | $ | (2.6 | ) | $ | 3.0 | | $ | (7.0 | ) | $ | 37.3 | |
Plus: | | | | | | | | | | | | | |
DD&A | | 22.1 | | 8.1 | | 3.0 | | — | | 3.0 | | 36.3 | |
Interest expense | | 3.0 | | 0.8 | | 0.6 | | — | | 1.8 | | 6.1 | |
EBITDA from continuing operations†** | | $ | 41.6 | | $ | 36.3 | | $ | 1.0 | | $ | 3.0 | | $ | (2.2 | ) | $ | 79.7 | |
Plus: Rhino Eastern DD&A-51% | | — | | — | | — | | 1.5 | | — | | 1.5 | |
Plus: Rhino Eastern interest expense-51% | | — | | — | | — | | 0.1 | | — | | 0.1 | |
Adjusted EBITDA from continuing operations† ** | | 41.6 | | 36.3 | | 1.0 | | 4.5 | | (2.2 | ) | 81.2 | |
Net income from discontinued operations | | — | | — | | — | | — | | — | | — | |
DD&A included in net income from discontinued operations | | — | | — | | — | | — | | — | | — | |
Adjusted EBITDA † | | $ | 41.6 | | $ | 36.3 | | $ | 1.0 | | $ | 4.5 | | $ | (2.2 | ) | $ | 81.2 | |
* Includes our 51% equity interest in the results of the joint venture, which owns the Rhino Eastern mining complex located in West Virginia and for which we serve as manager.
† Calculated based on actual amounts and not the rounded amounts presented in this table.
** Totals may not foot due to rounding
*** During the first quarter of 2013, we incurred a non-cash expense of approximately $0.9 million due to the write-off of a continuous miner that was damaged at one of our underground mines in Central Appalachia. In addition, during the fourth quarter of 2013, we made a strategic decision to permanently close the mining operations at our McClane Canyon mine in Colorado, which resulted in a non-cash impairment charge of approximately $1.7 million. We believe that the isolation and presentation of these specific items to arrive at Adjusted EBITDA is useful because it enhances investors’ understanding of how we assess the performance of our business. We believe the adjustment of these items provides investors with additional information that they can utilize in evaluating our performance. Additionally, we believe the isolation of these items provides investors with enhanced comparability to prior and future periods of our operating results.
Liquidity and Capital Resources
Liquidity
Our business is capital intensive and requires substantial capital expenditures for purchasing, upgrading and maintaining equipment used in developing and mining our reserves, as well as complying with applicable environmental and mine safety laws and regulations. Our principal liquidity requirements are to finance current operations, fund capital
expenditures, including acquisitions from time to time, service our debt and make distributions to our unitholders. Our sources of liquidity include cash generated by our operations, borrowings under our credit agreement and further issuances of equity and debt securities.
The principal indicators of our liquidity are our cash on hand and availability under our credit agreement. As of December 31, 2013, our available liquidity was $56.5 million, including cash on hand of $0.4 million and $56.1 million of available borrowing capacity under our credit agreement. The amount available under our credit agreement is based upon a maximum borrowing capacity of 3.75 times a trailing twelve-month EBITDA calculation (as defined in the credit agreement).
Please read “—Capital Expenditures” for a further discussion of the impact on liquidity.
Cash Flows
Year Ended December 31, 2013 Compared to Year Ended December 31, 2012
Net cash provided by operating activities was $51.7 million for the year ended December 31, 2013 as compared to $79.7 million for the year ended December 31, 2012. This decrease in cash provided by operating activities was primarily the result of lower net income, which resulted from decreased tons sold and revenue as well as unfavorable results from our Rhino Eastern joint venture.
Net cash used in investing activities was $43.9 million for the year ended December 31, 2013 as compared to $58.4 million for the year ended December 31, 2012. The decrease in cash used in investing activities was primarily due to the decreased amounts expended for the purchase and construction of mining equipment. For the year ended December 31, 2012, our primary expenditures related to the new preparation plant in our Tug River mining complex, which resulted in increased expenditures when compared to the year ended December 31, 2013. In addition, the $10.5 million received from the sale of our 20% royalty interest on our Utica Shale property in the year ended December 31, 2013 resulted in lower net cash used in investing activities when compared to 2012.
Net cash used in financing activities for the year ended December 31, 2013 was $7.9 million, which was primarily attributable to distributions paid to our unitholders, partially offset by net borrowings under our credit agreement that were primarily used to fund a portion of our capital expenditures. Net cash used in financing activities for the year ended December 31, 2013 also included the net proceeds from our public offering of common units, which resulted in net proceeds after offering expenses of approximately $14.6 million that was used to repay outstanding debt. Net cash used in financing activities for the year ended December 31, 2012 was $21.3 million, which was primarily attributable to distributions paid to our unitholders, partially offset by net borrowings under our credit agreement that were primarily used to fund a portion of our capital expenditures.
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
Net cash provided by operating activities was $79.7 million for the year ended December 31, 2012 as compared to $66.9 million for the year ended December 31, 2011. This increase in cash provided by operating activities was the result of an increase in net income, primarily due to the $7.4 million of income from the lease bonus payments received on our Utica acreage lease, as well as favorable changes in our working capital accounts year to year.
Net cash used in investing activities was $58.4 million for the year ended December 31, 2012 as compared to $188.0 million for the year ended December 31, 2011. The decrease in cash used in investing activities was primarily due to the acquisition of Elk Horn in 2011 for approximately $119.6 million, net of cash acquired, along with decreased amounts expended for additions to property, plant and equipment in 2012 compared to 2011, primarily due to approximately $28.0 million expended for oil and natural gas mineral rights acquisitions in the Cana Woodford region and the Utica Shale region in 2011.
Net cash used in financing activities for the year ended December 31, 2012 was $21.3 million, which was primarily attributable to distributions paid to our unitholders, partially offset by net borrowings under our credit agreement that were primarily used to fund a portion of our capital expenditures. Net cash provided by financing activities for the year ended December 31, 2011 was $121.5 million, which was primarily attributable to net borrowings under our credit agreement to fund the Elk Horn acquisition that was also partially funded with the net proceeds of approximately $66.9 million from the public offering of common units in July 2011.
Capital Expenditures
Our mining operations require investments to expand, upgrade or enhance existing operations and to meet environmental and safety regulations. Maintenance capital expenditures are those capital expenditures required to maintain our long-term operating capacity. For example, maintenance capital expenditures include expenditures associated with the replacement of equipment and coal reserves, whether through the expansion of an existing mine or the acquisition or development of new reserves, to the extent such expenditures are made to maintain our long-term operating capacity. Expansion capital expenditures are those capital expenditures that we expect will increase our operating capacity over the long term. Examples of expansion capital expenditures include the acquisition of reserves, acquisition of equipment for a new mine or the expansion of an existing mine to the extent such expenditures are expected to expand our long-term operating capacity.
Actual maintenance capital expenditures for the year ended December 31, 2013 were approximately $14.2 million. These amounts were primarily used to rebuild, repair or replace older mining equipment. Expansion capital expenditures for the year ended December 31, 2013 were approximately $40.3 million, which were primarily related to additional investment in our oil and natural gas properties in the Utica Shale region, as well as the initial development of our new Pennyrile mine in western Kentucky. The remaining amount of expansion capital expenditures was primarily spent on our internal development projects. For the year ending December 31, 2014, we have budgeted $7 million to $10 million for maintenance capital expenditures. We expect a decrease in our 2014 expansion capital expenditures since we entered into a binding agreement in February 2014 to sell our entire Utica Shale interests to Gulfport, which was consummated in March 2014.
We believe that we have sufficient liquid assets, cash flows from operations and borrowing capacity under our credit agreement to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures for the next twelve months. However, we are subject to business and operational risks that could adversely affect our cash flow. A material decrease in our cash flows would likely produce a corollary adverse effect on our borrowing capacity and our ability to pay distributions to our unitholders. In addition, we have not paid any distributions on our subordinated units for any quarter after the quarter ended March 31, 2012. From time to time, we may issue debt and equity securities.
Credit Agreement
The original maximum availability under our credit facility with PNC Bank, N.A. as administrative agent, was $200.0 million. On June 8, 2011, with the consent of the lenders, we exercised the option to increase the amount available to borrow under the credit agreement by $50.0 million to $250.0 million as part of the Elk Horn acquisition.
On July 29, 2011, we executed an amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and a group of participating lenders. The maximum availability under the amended and restated credit facility is $300.0 million, with a one-time option to increase the availability by an amount not to exceed $50.0 million. Of the $300.0 million, $75.0 million is available for letters of credit.
Loans under the credit agreement bear interest at either (i) a base rate equaling the highest of (a) the Federal Funds Open Rate plus 0.50%; (b) the prime rate; or (c) daily LIBOR plus 1.00%, plus an applicable margin in each case or (ii) LIBOR plus an applicable margin, at our option. The applicable margin for the base rate option is 1.50% to 2.50%, and the applicable margin for the LIBOR option is 2.50% to 3.50%, each of which depends on our and our subsidiaries’ consolidated leverage ratio (“Consolidated Leverage Ratio”). The credit agreement also contains letter of credit fees equal to an applicable margin of 2.50% to 3.50% depending on the Consolidated Leverage Ratio, multiplied by the aggregate amount available to be drawn on the letters of credit, and a 0.15% fronting fee payable to the administrative agent. In addition, we incur a commitment fee on the unused portion of the credit agreement at a rate of 0.375% to 0.50% per annum, depending on the Consolidated Leverage Ratio. Borrowings on the line of credit are collateralized by all of our unsecured assets.
Our credit agreement requires us to maintain certain minimum financial ratios and contains certain restrictive provisions, including among others, restrictions on making loans, investments and advances, incurring additional indebtedness, guaranteeing indebtedness, creating liens, and selling or assigning units. As of and for the year ended December 31, 2013, we are in compliance with respect to all covenants contained in the credit agreement. The credit agreement expires in July 2016.
On April 19, 2013, we entered into an amendment of the amended and restated senior secured credit facility. The amendment provided for an increase in the maximum allowed investments in coal-related entities outside of our current partnership structure (i.e. joint ventures) under the amended and restated senior secured credit facility from $25 million to $40 million. The amendment also altered the maximum leverage ratio allowed under the amended and restated senior secured credit facility and also altered the pricing grid to include applicable interest rates for borrowings, letter of credit fees and commitment fees on unused borrowings based upon the new maximum leverage ratio. The amendment increases the
maximum leverage ratio of the amended and restated senior secured credit facility to 3.75 from April 1, 2013 through March 31, 2015, then steps the maximum leverage ratio down to its previous level of 3.0 after December 31, 2015. All other terms of the amended and restated senior secured credit facility were not affected by the amendment.
At December 31, 2013, we had borrowed $162.0 million at a variable interest rate of LIBOR plus 3.00% (3.17% at December 31, 2013) and an additional $5.0 million at a variable interest rate of the prime rate plus 2.00% (5.25% at December 31, 2013). In addition, we had outstanding letters of credit of approximately $21.5 million at a fixed interest rate of 3.00% at December 31, 2013. Based upon a maximum borrowing capacity of 3.75 times a trailing twelve-month EBITDA calculation (as defined in the credit agreement), we had not used $56.1 million of the borrowing availability at December 31, 2013. During the three month period ended December 31, 2013, we had average borrowings outstanding of approximately $161.1 million under our credit agreement.
Off-Balance Sheet Arrangements
In the normal course of business, we are a party to off-balance sheet arrangements that include guarantees and financial instruments with off-balance sheet risk, such as bank letters of credit and surety bonds. No liabilities related to these arrangements are reflected in our consolidated balance sheet, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.
Federal and state laws require us to secure certain long-term obligations related to mine closure and reclamation costs. We typically secure these obligations by using surety bonds, an off-balance sheet instrument. The use of surety bonds is less expensive for us than the alternative of posting a 100% cash bond or a bank letter of credit, either of which would require a greater use of our credit agreement. We then use bank letters of credit to secure our surety bonding obligations as a lower cost alternative than securing those bonds with a committed bonding facility pursuant to which we are required to provide bank letters of credit in an amount of up to 25% of the aggregate bond liability. To the extent that surety bonds become unavailable, we would seek to secure our reclamation obligations with letters of credit, cash deposits or other suitable forms of collateral.
As of December 31, 2013, we had $21.5 million in letters of credit outstanding, of which $17.2 million served as collateral for approximately $75.2 million in our surety bonds outstanding that secure the performance of our reclamation obligations.
Contractual Obligations
The following table summarizes by period the payments due for our estimated contractual obligations as of December 31, 2013:
| | Payments Due by Period | |
| | Total | | Less than 1
Year | | 1-3 Years | | 4-5 Years | | More than 5
Years | |
| | (in thousands) | |
Long-term debt obligations (including interest) (1) | | 171,046 | | $ | 1,024 | | $ | 167,475 | | $ | 498 | | $ | 2,049 | |
Asset retirement obligations | | 34,492 | | 1,614 | | 7,104 | | 1,955 | | 23,819 | |
Operating lease obligations (2) | | 5,994 | | 1,577 | | 3,083 | | 1,334 | | — | |
Ammonia nitrate obligations | | 927 | | 927 | | — | | — | | — | |
Advance royalties (3) | | 18,866 | | 1,642 | | 3,729 | | 3,851 | | 9,644 | |
Retiree medical obligations | | 6,867 | | 334 | | 935 | | 1,261 | | 4,337 | |
Total | | $ | 238,192 | | $ | 7,118 | | $ | 182,326 | | $ | 8,899 | | $ | 39,849 | |
| | | | | | | | | | | | | | | | |
(1) Assumes a current LIBOR of 0.17% plus the applicable margin for all periods.
(2) Some of our surface mining equipment and a coal handling and loading facility are categorized as operating leases. These leases have maturity dates ranging from three to five years.
(3) We have obligations on various coal and land leases to prepay certain amounts which are recoupable in future years when mining occurs
Critical Accounting Policies and Estimates
Our financial statements are prepared in accordance with accounting principles that are generally accepted in the United States. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amount of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities. Management evaluates its estimates and judgments on an on-going basis. Management bases its estimates and judgments on historical experience and other factors that are believed to be reasonable under the circumstances. Nevertheless, actual results may differ from the estimates used and judgments made. Note 2 to the audited consolidated financial statements included elsewhere in this report provides a summary of all significant accounting policies and refer to Note 13 for information on our postretirement plan. We believe that of these significant accounting policies, the following may involve a higher degree of judgment or complexity.
Investment in Joint Ventures
Investments in joint ventures are accounted for using the consolidation, equity method or cost basis depending upon the level of ownership, our ability to exercise significant influence over the operating and financial policies of the investee and whether we are determined to be the primary beneficiary of a variable interest in an entity. Equity investments are recorded at original cost and adjusted periodically to recognize our proportionate share of the investees’ net income or losses after the date of investment. Any losses from our equity method investment are absorbed by us based upon our proportionate ownership percentage. If losses are incurred that exceed our investment in the equity method entity, then we must continue to record our proportionate share of losses in excess of our investment. Investments are written down only when there is clear evidence that a decline in value that is other than temporary has occurred.
In May 2008, we entered into a joint venture, Rhino Eastern, with an affiliate of Patriot to acquire the Rhino Eastern mining complex. To initially capitalize the Rhino Eastern joint venture, we contributed approximately $16.1 million for a 51% ownership interest in the joint venture, and we account for the investment in the joint venture and its results of operations under the equity method. We consider the operations of this entity to comprise a reporting segment (“Eastern Met”) and have provided supplemental detail related to this operation in Note 21 to the audited consolidated financial statements that are included elsewhere in this report.
In determining that we were not the primary beneficiary of the variable interest entity for the years ended December 31, 2013, 2012 and 2011, we performed a qualitative and quantitative analysis based on the controlling economic interests of the Rhino Eastern joint venture. This included an analysis of the expected economic contributions of the joint venture. We concluded that we are not the primary beneficiary of the joint venture primarily because of certain contractual arrangements by the joint venture with Patriot and the fact that the Rhino Eastern joint venture is managed by a committee of an equal number of representatives from Patriot and us. Mandatory pro rata additional contributions not to exceed $10 million in the aggregate could be required of the joint venture partners, which we would be obligated to fund based upon our 51% ownership interest.
As of December 31, 2013 and 2012, we have recorded our equity method investment of $19.4 million and $21.4 million, respectively, as a long-term asset. During the year ended December 31, 2013, we made capital contributions to the Rhino Eastern joint venture of approximately $2.3 million based upon our proportionate ownership percentage. As disclosed in Note 19 to the audited consolidated financial statements that are included elsewhere in this report, we provided loans to the Rhino Eastern joint venture during 2012 that totaled approximately $11.9 million, which were fully repaid as of December 31, 2012.
Property, Plant and Equipment
Property, plant, and equipment, including coal properties, oil and natural gas properties, mine development costs and construction costs, are recorded at cost, which includes construction overhead and interest, where applicable. Expenditures for major renewals and betterments are capitalized, while expenditures for maintenance and repairs are expensed as incurred. Mining and other equipment and related facilities are depreciated using the straight-line method based upon the shorter of estimated useful lives of the assets or the estimated life of each mine. Coal properties, as well as oil and natural gas properties, are depleted using the units-of-production method, based on estimated proven and probable reserves. Mine development costs are amortized using the units-of-production method, based on estimated proven and probable reserves. Gains or losses arising from sales or retirements are included in current operations.
On March 30, 2005, the Financial Accounting Standards Board (FASB) ratified the consensus reached by the Emerging Issues Task Force, or EITF, on accounting for stripping costs in the mining industry. This accounting guidance applies to stripping costs incurred in the production phase of a mine for the removal of overburden or waste materials for the
purpose of obtaining access to coal that will be extracted. Under the guidance, stripping costs incurred during the production phase of the mine are variable production costs that are included in the cost of inventory produced and extracted during the period the stripping costs are incurred. We have recorded stripping costs for all of our surface mines incurred during the production phase as variable production costs that are included in the cost of inventory produced. We define a surface mine as a location where we utilize operating assets necessary to extract coal, with the geographic boundary determined by property control, permit boundaries, and/or economic threshold limits. Multiple pits that share common infrastructure and processing equipment may be located within a single surface mine boundary, which can cover separate coal seams that typically are recovered incrementally as the overburden depth increases. In accordance with the accounting guidance for extractive mining activities, we define a mine in production as one from which saleable minerals have begun to be extracted (produced) from an ore body, regardless of the level of production; however, the production phase does not commence with the removal of de minimis saleable mineral material that occurs in conjunction with the removal of overburden or waste material for the purpose of obtaining access to an ore body. We capitalize only the development cost of the first pit at a mine site that may include multiple pits.
Asset Impairments
We follow the accounting guidance on the impairment or disposal of property, plant and equipment, which requires that projected future cash flows from use and disposition of assets be compared with the carrying amounts of those assets when potential impairment is indicated. When the sum of projected undiscounted cash flows is less than the carrying amount, impairment losses are recognized. In determining such impairment losses, we must determine the fair value for the assets in question in accordance with the applicable fair value accounting guidance. Once the fair value is determined, the appropriate impairment loss must be recorded as the difference between the carrying amount of the assets and their respective fair values. Also, in certain situations, expected mine lives are shortened because of changes to planned operations. When that occurs and it is determined that the mine’s underlying costs are not recoverable in the future, reclamation and mine closing obligations are accelerated and the mine closing accrual is increased accordingly. To the extent it is determined that asset carrying values will not be recoverable during a shorter mine life, a provision for such impairment is recognized.
During the fourth quarter of 2013, we made a strategic decision to permanently close the mining operations at our McClane Canyon mine in Colorado. Since the McClane Canyon mine had been idled at the end of 2010, we had been actively marketing the coal from this mine to potential buyers, but had not been able to obtain suitable sales contracts. Due to the unfavorable long-term prospects for the coal market in the Colorado area and to avoid the ongoing costs that were being incurred to actively idle this mine, we made the decision to permanently close this operation at the end of 2013. While a portion of the equipment from this operation was relocated to other operating locations, we incurred an impairment charge of approximately $1.7 million during 2013 related to specific property, plant and equipment at this complex. There were no impairment losses recorded during the years ended December 31, 2012 and 2011.
Asset Retirement Obligations
The accounting guidance for asset retirement obligations addresses asset retirement obligations that result from the acquisition, construction, or normal operation of long-lived assets. This guidance requires companies to recognize asset retirement obligations at fair value when the liability is incurred or acquired. Upon initial recognition of a liability, an amount equal to the liability is capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. We have recorded the asset retirement costs in Coal properties.
We estimate our future cost requirements for reclamation of land where we have conducted surface and underground mining operations, based on our interpretation of the technical standards of regulations enacted by the U.S. Office of Surface Mining, as well as state regulations. These costs relate to reclaiming the pit and support acreage at surface mines and sealing portals at underground mines. Other reclamation costs are related to refuse and slurry ponds, as well as holding and related termination or exit costs.
We expense contemporaneous reclamation which is performed prior to final mine closure. The establishment of the end of mine reclamation and closure liability is based upon permit requirements and requires significant estimates and assumptions, principally associated with regulatory requirements, costs and recoverable coal reserves. Annually, we review our end of mine reclamation and closure liability and make necessary adjustments, including mine plan and permit changes and revisions to cost and production levels to optimize mining and reclamation efficiency. When a mine life is shortened due to a change in the mine plan, mine closing obligations are accelerated, the related accrual is increased and the related asset is reviewed for impairment, accordingly.
The adjustments to the liability from annual recosting reflect changes in expected timing, cash flow, and the discount rate used in the present value calculation of the liability. Each respective year includes a range of discount rates that are dependent upon the timing of the cash flows of the specific obligations. Changes in the asset retirement obligations for the year ended December 31, 2013 were calculated with discount rates that ranged from 2.3% to 5.6%. Changes in the asset retirement obligations for the year ended December 31, 2012 were calculated with discount rates that ranged from 3.2% to 5.3%. Changes in the asset retirement obligations for the year ended December 31, 2011 were calculated with discount rates that ranged from 4.2% to 7.0%. The discount rates changed from previous years due to changes in applicable market indicators that are used to arrive at an appropriate discount rate. Other recosting adjustments to the liability are made annually based on inflationary cost increases or decreases and changes in the expected operating periods of the mines. The related inflation rate utilized in the recosting adjustments was 2.3% for 2013 and 2012, and 2.50% for 2011.
Workers’ Compensation and Pneumoconiosis (“black lung”) Benefits
Certain of our subsidiaries are liable under federal and state laws to pay workers’ compensation and coal workers’ black lung benefits to eligible employees, former employees and their dependents. We currently utilize an insurance program and state workers’ compensation fund participation to secure our on-going obligations depending on the location of the operation. Premium expense for workers’ compensation benefits is recognized in the period in which the related insurance coverage is provided.
Our black lung benefit liability is calculated using the service cost method that considers the calculation of the actuarial present value of the estimated black lung obligation. The actuarial calculations using the service cost method for our black lung benefit liability are based on numerous assumptions including disability incidence, medical costs, mortality, death benefits, dependents and interest rates.
In addition, our liability for traumatic workers’ compensation injury claims is the estimated present value of current workers’ compensation benefits, based on actuarial estimates. The actuarial estimates for our workers’ compensation liability are based on numerous assumptions including claim development patterns, mortality, medical costs and interest rates.
Revenue Recognition
Most of our revenues are generated under supply contracts with electric utilities, industrial companies or other coal-related organizations, primarily in the eastern United States. Revenue is recognized and recorded when shipment or delivery to the customer has occurred, prices are fixed or determinable and the title or risk of loss has passed in accordance with the terms of the supply contract. Under the typical terms of these contracts, risk of loss transfers to the customers at the mine or port, when the coal is loaded on the rail, barge, truck or other transportation source that delivers coal to its destination. Advance payments are deferred and recognized in revenue as coal is shipped and title has passed.
Coal revenues also result from the sale of brokered coal produced by others. The revenues related to brokered coal sales are included in coal revenues on a gross basis and the corresponding cost of the coal from the supplier is recorded in cost of coal sales in accordance with the revenue recognition accounting guidance on principal agent considerations.
Freight and handling costs paid directly to third-party carriers and invoiced to coal customers are recorded as freight and handling costs and freight and handling revenues, respectively.
Other revenues generally consist of coal royalty revenues, limestone sales, coal handling and processing, rebates and rental income. Coal royalty revenues are recognized on the basis of tons of coal sold by our lessees and the corresponding gross revenues from those sales. The leases are based on (1) minimum monthly or annual payments, (2) a minimum dollar royalty per ton and/or a percentage of the gross sales price, or (3) a combination of both. Coal royalty revenues are recorded from royalty reports submitted by the lessee, which are reconciled and subject to audit by us. Most of our lessees are required to make minimum monthly or annual royalty payments that are recoupable over certain time periods, generally two years. If tonnage royalty revenues do not meet the required minimum amount, the difference is paid as a deficiency. These deficiency payments received are recognized as an unearned revenue liability because they are generally recoupable over certain time periods. When a lessee recoups a deficiency payment through production, the recouped amount is deducted from the unearned revenue liability and added to revenue attributable to the coal royalty revenue in the current period. If a lessee does not recoup a deficiency paid during the allocated time period, the recoupment right lost becomes revenue in the current period and is deducted from the liability.
With respect to other revenues recognized in situations unrelated to the shipment of coal, we carefully review the facts and circumstances of each transaction and do not recognize revenue until the following criteria are met: persuasive evidence of an arrangement exists, delivery has occurred or services have been rendered, the seller’s price to the buyer is
fixed or determinable and collectibility is reasonably assured. Advance payments received are deferred and recognized in revenue when earned.
Derivative Financial Instruments
We occasionally use diesel fuel forward contracts to manage the risk of fluctuations in the cost of diesel fuel. Our diesel fuel forward contracts qualify for the normal purchase normal sale, or NPNS, exception prescribed by the accounting guidance on derivatives and hedging, based on the terms of the contracts and management’s intent and ability to take physical delivery of the diesel fuel.
Income Taxes
We are considered a partnership for income tax purposes. Accordingly, the partners report our taxable income or loss on their individual tax returns.
Recent Accounting Pronouncements
In February 2013, the FASB issued ASU No. 2013-02, “Comprehensive Income (Topic 220) Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income”. This ASU requires preparers to report, in one place, information about reclassifications out of accumulated other comprehensive income (“AOCI”). The ASU also requires companies to report changes in AOCI balances. For significant items reclassified out of AOCI to net income in their entirety in the same reporting period, reporting (either on the face of the statement where net income is presented or in the notes) is required about the effect of the reclassifications on the respective line items in the statement where net income is presented. For items that are not reclassified to net income in their entirety in the same reporting period, a cross reference to other disclosures currently required under US GAAP (e.g., pension amounts that are included in inventory) is required in the notes. The above information must be presented in one place (parenthetically on the face of the financial statements by income statement line item or in a note). Public companies must provide the information required by the ASU (e.g., changes in AOCI balances and reclassifications out of AOCI) in interim and annual periods. For public companies, the ASU is effective for fiscal years and interim periods within those years beginning after 15 December 2012, or the first quarter of 2013 for calendar-year companies. We have included the required disclosures of ASU 2013-02 in this report and this ASU did not have a material effect on us.
