SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
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ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended: December 31, 2012 OR
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TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Commission file number: 0-14731
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“COAL KEEPS YOUR LIGHTS ON”
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“COAL KEEPS YOUR LIGHTS ON”
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HALLADOR ENERGY COMPANY
(www.halladorenergy.com)
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COLORADO
(State of incorporation)
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84-1014610
(IRS Employer Identification No.)
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1660 Lincoln Street, Suite 2700, Denver, Colorado
(Address of principal executive offices)
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80264-2701
(Zip Code)
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Issuer's telephone number: 303.839.5504
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Securities registered pursuant to Section 12(b) of the Exchange Act: NONE
Securities registered pursuant to Section 12(g) of the Exchange Act: Common Stock, $.01 par value
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15 (d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "larger accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
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o Large accelerated filer
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o Accelerated filer
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o Non-accelerated filer (do not check if a small reporting company)
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þ Smaller reporting company
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.) Yes o No þ
The aggregate market value of the common stock held by non-affiliates (public float) on June 30, 2012 was $64 million based on the closing price reported that date by the NASDAQ of $8.48 per share.
As of March 6, 2013 we had 28.5 million shares outstanding. Portions of our information statement to be filed with the SEC in connection with our annual stockholders’ meeting to be held on Thursday, April 18, 2013 are incorporated by reference into Part III of this Form 10-K.
1
PART 1
ITEM 1. BUSINESS.
General Development of Business
In December 2009 we changed our name from Hallador Petroleum Company to Hallador Energy Company. We are a Colorado corporation organized by our predecessor in 1949. 70% of our stock is held by officers, directors and their affiliates. Our stock is thinly traded (average daily volume is 19,000 shares) on the NASDAQ Capital Market listing under the symbol HNRG.
The largest portion of our business is devoted to coal mining in the state of Indiana through Sunrise Coal LLC (a wholly-owned subsidiary) serving the electric power generation industry. We also own a 45% equity interest in Savoy Energy, L.P., a private oil and gas (O&G) exploration and production (E&P) company with operations in Michigan and a 50% interest in Sunrise Energy, LLC, a private O&G E&P company with operations in Indiana. We account for our investments in Savoy and Sunrise Energy using the equity method. Historically, through our Denver operations, we also lease oil and gas mineral rights with the intent to sell the prospects to third parties and retain an overriding royalty interest (ORRI) or carried interest. In mid-July 2012 we decided to substantially reduce these activities and our geologist who developed these prospects now works for us on a part-time basis.
Active Reserve (assigned) - Carlisle Mine (underground)
Our coal reserves at December 31, 2012 assigned to the Carlisle mine were 43.5 million tons (34.2 proven and 9.3 probable) compared to beginning of year reserves of 46 million tons. Primarily through the execution of new leases, our reserve additions of 1.18 million tons replaced about 40% of our 2012 production of three million tons. We reduced our reserves by 700,000 tons due to revised mining plans. The mine is located near the town of Carlisle, Indiana in Sullivan County and became operational in January 2007. The coal is accessed with a slope to a depth of 340'. The coal is mined in the Indiana Coal V seam which is highly volatile bituminous coal and is the most economically significant coal in Indiana. The Indiana V seam has been extensively mined by underground and surface methods in the general area. The coal thickness in the project area is 4’ to 7’.
The mine has several advantages as listed below:
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SO2 - Historically, Carlisle has guaranteed a 6.0lb SO product, however, with the addition of Ace we can blend lower sulfur coal with Carlisle coal and guarantee a mid-sulfur product which should command a higher price. Few mines in the ILB have the ability to offer their customers various ranges of SO2. The Carlisle Mine has supplied coal to 11 different power plants. With the addition of low sulfur blend coal from Ace we expect our list of customers to grow.
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Chlorine - Our reserves have lower chlorine (<0.10%) than the average ILB of 0.22%. Much of the ILB’s new production is located in Illinois and possesses chlorine content in excess of .30%. The relatively low chlorine content of our reserves is attractive to buyers given their desire to limit the corrosive effects of chlorine in their power plants.
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Transportation - The Carlisle mine has a double 100 rail car loop facility and a four-hour certified batch load out facility connected to the CSX railroad. The Indiana Rail Road (INRD) also has limited running rights on the CSX to our mine. Dual rail access gives us a freight advantage to more customers. Long term, the CSX anticipates our coal being shipped to southeast markets via their railroad. We sell our coal FOB the mine and substantially all of our coal is transported by rail. However, on occasion we have shipped to three power plants via truck.
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New Mine (assigned) - Ace-in-the-Hole Mine (surface)
In November of 2012 we purchased for $6 million permitted fee coal reserves, coal leases and surface properties near Clay City, Indiana in Clay County. The Ace-in-the-Hole Mine is 42 road miles northeast of the Carlisle Mine. We control 3.1 million tons of proven coal reserves of which we own 1.2 million tons in fee. We will mine two primary seams of low sulfur coal which make up 2.9 million of the 3.1 million tons controlled. Both of the primary seams are low sulfur (2# SO2). Mine development began in late December 2012 and we expect to be shipping coal in March of 2013. We plan to truck low sulfur coal from Ace to Carlisle to blend with Carlisle’s high sulfur coal. Many utilities in the southeastern U.S. have scrubbers with lower sulfur limits (4# SO2) which cannot accept the higher sulfur contents of the Illinois Basin (ILB) (6# SO2). Blending Carlisle coal to a lower sulfur specification will enable us to market Carlisle coal to more customers. We currently have a contract at Carlisle which will require us to blend coal from Ace to meet sulfur specifications. We also expect to ship low sulfur coal from Ace direct to unscrubbed customers that require low sulfur (2# SO2). We expect the maximum capacity of Ace to be 500,000 tons annually. Ace currently has 20% of its capacity contracted for 2013 and 2014. We have invested $3 million in equipment and development as of December 31, 2012 and we anticipate investing an additional $5.5 million in equipment and development in 2013.
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New Reserve (unassigned) - Bulldog Mine
We have leased roughly 19,300 acres in Vermillion County, Illinois near the village of Allerton. Based on our reserve estimates we currently control 35.6 million tons of coal reserves (19.5 proven and 16.1 probable). A considerable amount of our leased acres has yet to receive any exploratory drilling, thus we anticipate our controlled reserves to grow as we continue drilling in 2013. The permitting process was started in the summer of 2011 and we filed the formal permit with the state of Illinois and the appropriate Federal regulators during June 2012. We currently expect to receive an approved mining permit in the first quarter of 2014.
Full-scale mine development will not commence until we have a sales commitment.
New Reserve (unassigned) - Russellville
We have leased roughly 11,000 acres in Lawrence County, Illinois near the village of Russellville. Based on our reserve estimates we currently control 29.4 million tons of coal reserves (15.5 proven and 13.9 probable). The permitting process will start this fall and we anticipate filing the formal permit with the appropriate regulators during the second quarter of 2014. This reserve is located about twenty miles southwest of the Carlisle mine. Our initial testing indicates that this reserve’s minability and coal quality is very similar to the Carlisle reserve.
Unassigned reserves represent coal reserves that would require new mineshafts, mining equipment and plant facilities before operations could begin on the property. The primary reason for this distinction is to inform investors which coal reserves will require substantial capital expenditures before production can begin.
Reserve Table - Controlled Tons (in millions):
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Year End Reserves
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Annual Capacity
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2012
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2011
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Carlisle (assigned)
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3.3
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43.5
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46.0
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Ace-in-the-Hole (assigned)
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.5
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3.1
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Bulldog (unassigned)
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35.6
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32.3
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Russellville (unassigned)
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29.4
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Total
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3.8
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111.6
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78.3
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For 2012, we were able to increase our controlled reserves by 33.3 million tons or 43%. Additionally, we increased our production capacity, through the addition of Ace, by .5 million tons annually or 15%.
Our Coal Contracts
Over the past three years we sold over 90% of our coal to three investment-grade customers. We have close relationships with these customers: Duke Energy Corporation (NYSE:DUK), Hoosier Energy, an electric cooperative, and Indianapolis Power & Light Company, a wholly-owned subsidiary of The AES Corporation (NYSE:AES). During 2011 we sold 300,000 tons of coal to Jacksonville Electric Authority (JEA). The addition of JEA is noteworthy as this was the first time we have sold coal to a customer as far as Jacksonville, Florida. We have no more contracts with JEA. During 2012 we sold 185,000 tons to an Orlando utility through an arrangement we have with an affiliate of JP Morgan. We believe these sales are an indication of the trend of ILB coal replacing CAAP coal that has traditionally supplied the southeast markets. We sell about one million tons per year to each of our three major customers.
The table below illustrates the status of our current coal contracts:
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Year
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Contracted Tons
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Average Price/Ton
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2013
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3,221,000
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$40.49
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2014
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1,700,000
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$45.01
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Total
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4,921,000
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We expect to continue selling a significant portion of our coal under supply agreements with terms of one year or longer. Our approach is to selectively renew, blend and extend existing contracts, or enter into new, coal supply contracts when we can do so at prices we believe are favorable. It is our goal to maintain or increase our traditional average sales price per ton.
Typically, customers enter into coal supply agreements to secure reliable sources of coal at predictable prices while we seek stable sources of revenue to support the investments required to open, expand and maintain or improve productivity at the mines needed to supply these contracts. The terms of coal supply agreements result from competitive bidding and extensive negotiations with customers.
Suppliers
The main types of goods we purchase are mining equipment and replacement parts, steel-related (including roof control) products, belting products, lubricants, electricity, fuel and tires. Although we have many long, well-established relationships with our key suppliers, we do not believe that we are dependent on any of our individual suppliers other than for purchases of electricity. The supplier base providing mining materials has been relatively consistent in recent years. Purchases of certain underground mining equipment are concentrated with one principle supplier; however, supplier competition continues to develop.
Illinois Basin (ILB)
The coal industry underwent a significant transformation in the early 1990s, as greater environmental accountability was established in the electric utility industry. Through the U.S. Clean Air Act, acceptable baseline levels were established for the release of sulfur dioxide in power plant emissions. In order to comply with the new law, most utilities switched fuel consumption to low-sulfur coal, thereby stripping the ILB of over 50 million tons of annual coal demand. This strategy continued until mid 2000 when a shortage of low-sulfur coal drove up prices. This price increase combined with the assurance from the U.S. government that the utility industry would be able to recoup their costs to install scrubbers caused utilities to begin investing in scrubbers on a large scale. With scrubbers, the ILB has reopened as a significant fuel source for utilities and has enabled them to burn lower cost, high sulfur coal.
The ILB consists of coal mining operations covering more than 50,000 square miles in Illinois, Indiana and western Kentucky. The ILB is centrally located between four of the largest regions that consume coal as fuel for electricity generation (East North Central, West South Central, West North Central and East South Central). The region also has access to sufficient rail and water transportation routes that service coal-fired power plants in these regions as well as other significant coal consuming regions of the South Atlantic and Middle Atlantic.
U. S. Coal Industry
According to the EIA, coal is expected to remain the largest energy source of electric power generation in the United States for the foreseeable future.
The major coal production basins in the U.S. include Central Appalachia (CAPP), Northern Appalachia (NAPP), Illinois Basin (ILB), Powder River Basin (PRB) and the Western Bituminous region (WB). CAPP includes eastern Kentucky, Tennessee, Virginia and southern West Virginia. NAPP includes Maryland, Ohio, Pennsylvania and northern West Virginia. The ILB includes Illinois, Indiana and western Kentucky. The PRB is located in northeastern Wyoming and southeastern Montana. The WB includes western Colorado, eastern Utah and southern Wyoming.
Coal type varies by basin. Heat value and sulfur content are important quality characteristics and determine the end use for each coal type.
Coal in the U.S. is mined through surface and underground mining methods. The primary underground mining techniques are longwall mining and continuous (room-and-pillar) mining. The geological conditions dictate which technique to use. The Carlisle mine uses the continuous technique. In continuous mining, rooms are cut into the coal bed leaving a series of pillars, or columns of coal, to help support the mine roof and control the flow of air. Continuous mining equipment cuts the coal from the mining face. Generally, openings are driven 20’ wide and the pillars are rectangular in shape measuring 40’x 40’. As mining advances, a grid-like pattern of entries and pillars is formed. Roof bolts are used to secure the roof of the mine. Battery cars move the coal to the conveyor belt for transport to the surface. The pillars can constitute up to 50% of the total coal in a seam.
The United States coal industry is highly competitive, with numerous producers selling into all markets that use coal. We compete against large producers and hundreds of small producers. Peabody Energy Corporation (NYSE:BTU) and Alliance (NASDAQ:ARLP) are the two largest operators in the ILB producing slightly less than half the ILB’s coal production.
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There are some that believe natural gas (natgas) will overtake coal as the most economic way to produce electricity in the U.S. In the event the government places a price tag on carbon emissions, natgas would gain another advantage over coal since electricity from coal produces more carbon. The potential exists for natgas producers and utilities to develop a new relationship that has not been possible historically.
Employees
Our coal operations currently employ about 330 people. We use a consulting geologist when evaluating new coal mine projects. We also use a consultant to sell our coal, find new buyers and help in contract negotiations. The mine currently operates two production shifts and one maintenance shift while coal is produced 265-275 days of the year. All of our mines are non-union.
Safety and Environmental Regulations
Our operations, like operations of other coal companies, are subject to extensive regulation, primarily by federal and state authorities, on matters such as: air quality standards; reclamation and restoration activities involving our mining properties; mine permits and other licensing requirements; water pollution; employee health and safety; management of materials generated by mining operations; storage of petroleum products; protection of wetlands and endangered plant and wildlife protection. Many of these regulations require registration, permitting, compliance, monitoring and self-reporting and may impose civil and criminal penalties for non-compliance.
Additionally, the electric generation industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for our coal over time. The possibility exists that new legislation or regulations may be adopted or that the enforcement of existing laws could become more stringent, causing coal to become a less attractive fuel source and reducing the percentage of electricity generated from coal. Future legislation or regulation or more stringent enforcement of existing laws may have a significant impact on our mining operations or our customers’ ability to use coal.
While it is not possible to accurately quantify the expenditures we incur to maintain compliance with all applicable federal and state laws, those costs have been and are expected to continue to be significant. Federal and state mining laws and regulations require us to obtain surety bonds or post letters of credit from our banks to guarantee performance or payment of certain long-term obligations, including mine closure and reclamation costs.
Reclamation
The Carlisle mine began commercial production in February 2007 and is operating in compliance with all local, state, and federal regulations. We have no old mine properties to reclaim, other than the Howesville mine, which was operated for only eight months before it was closed in June 2006 due to safety concerns. During 2007, we finished Phase I of the reclamation of the Howesville mine. We expect the final phase to be completed by the end of 2015.
Mining Permits and Approvals
Numerous governmental permits or approvals are required for mining operations. When we apply for these permits and approvals, we may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production or processing of coal may have upon the environment. The authorization, permitting and implementation requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations. Regulations also provide that a mining permit or modification can be delayed, refused or revoked if an officer, director or a shareholder with a 10% or greater interest in the entity is affiliated with another entity that has outstanding permit violations. Thus, past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits.
In order to obtain mining permits and approvals from state regulatory authorities, mine operators must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior condition, productive use or other permitted condition. Typically, we submit the necessary permit applications several months before we plan to begin mining a new area. Some of our required permits are becoming increasingly more difficult and expensive to obtain, and the application review processes are taking longer to complete and becoming increasingly subject to challenge. Under some circumstances, substantial fines and penalties, including revocation or suspension of mining permits, may be imposed under the laws described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws. Compliance with these laws has increased the cost of coal mining for domestic coal producers.
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Mine Health and Safety Laws
We are proud of our safety record. We comply with the rules and regulation issued by the Mine Safety and Health Administration (MSHA) and also state rules and regulations. We applaud all reasonable rules and regulation that promote mine safety and keep our miners out of harm’s way. Complying with these existing rules and proposed rules add to our mining costs.
Clean Air Act and Related Regulations
The federal Clean Air Act and similar state laws and regulations which regulate emissions into the air, affect coal mining, coal handling and processing, primarily through permitting and/or emissions control requirements.
The Clean Air Act also indirectly affects coal mining operations by extensively regulating the air emissions of the coal-fired electric power generating plants operated by our customers. Coal contains impurities, such as sulfur, mercury and other constituents, many of which are released into the air when coal is burned. Carbon dioxide, a greenhouse gas (GHG), is also emitted when coal is burned. Environmental regulations governing emissions from coal-fired electric generating plants could affect demand for coal as a fuel source and affect the volume of our sales. For example, the federal Clean Air Act places limits on sulfur dioxide, nitrogen dioxide, and mercury emissions from electric power plants.
The installation of additional control measures to achieve regulatory emission reductions makes it more costly to operate coal-fired power plants and could make coal a less attractive fuel.
Other
We have no significant patents, trademarks, licenses, franchises or concessions.
Other than the 330 Sunrise Coal employees in Indiana, our CEO, CFO, controller, land person and two part time administrative staff work in the Denver office.
Our Denver office is located at 1660 Lincoln Street, Suite 2700, Denver, Colorado 80264, phone 303.839.5504 and Sunrise Coal's corporate office is located at 1183 Canvasback Drive, Terre Haute, Indiana 47802, phone 812.299.2800. Terre Haute is approximately 70 miles west of Indianapolis. Our website is www.halladorenergy.com and Sunrise Coal’s is www.sunrisecoal.com.
ITEM 1A. RISK FACTORS.
Smaller reporting companies are not required to provide the information required by this item.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
Smaller reporting companies are not required to provide the information required by this item; however, there were none.
ITEM 2. PROPERTIES.
See pages two - three for a discussion of our mines.
Coal Reserve Estimates
“Reserves” are defined by the SEC Industry Guide 7 (Guide 7) as that part of a mineral deposit, which could be economically and legally extracted or produced at the time of the reserve determination. “Recoverable” reserves mean coal that is economically recoverable using existing equipment and methods under federal and state laws currently in effect. “Proven (measured) reserves” are defined by Guide 7 as reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established. “Probable reserves” are defined by Guide 7 as reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation.
Our reserve estimates were prepared by Samuel Elder and Jacob Gennicks, two of our mining engineers. Mr. Elder is a licensed Professional Engineer in the State of Indiana and has over 25 years experience estimating coal reserves. Mr. Gennicks is a licensed Professional Engineer in the State of Indiana and Illinois and has three years experience estimating coal reserves.
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Standards set forth by the USGS were used to place areas of the mine reserves into the Proven (measured) and Probable (indicated) categories. Under these standards, coal within 1,320' of a data point is considered to be proven, and coal within 1,320' to 3,960' is placed in the Probable category. All reserves are stated as a final salable product.
ADDITIONAL DISCLOSURES FOR THE CARLISLE MINE
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1.
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The Carlisle mine currently has road frontage on State Highway 58, and is adjacent to the CSX railroad. The Carlisle mine has a double 100 car loop facility. Substantially all of our coal is shipped by rail.
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2.
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Currently only the Indiana V seam is planned to be mined, and all of the controlled tonnage is leased to Sunrise. Most leases have unlimited terms once mining has begun, and yearly payments or earned royalties are kept current. Mineable coal thickness used is greater than four feet. The current Carlisle mine plan is broken into four areas– North Main – South Main – West Main – 2 South Main. It is believed that all additional property that would be required to access all lease areas can be obtained but, if some properties cannot be leased, some modification of the current mine plan would be required. All coal should be mined within the terms of the leases. Leasing programs are continuing by our staff.
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3.
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The Carlisle mine has a dual-use slope for the main coal conveyor and the moving of supplies and personnel. There are two 8' diameter shafts at the base of the slope for mine ventilation. Two additional air shafts (8’ and 10.5’ diameter) were completed about three miles north of the original air shaft in 2009 to facilitate the mine expansion. The slope (9° or 15% grade) is 18' wide with concrete and steel arch construction. A 16’ hoist is about four miles north of the main slope. The hoist is currently facilitating two production units by efficiently moving personnel and materials into the north main and north main addition areas of the reserve. All underground mining equipment is powered with electricity and underground compliant diesel.
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4.
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The new slurry impoundment continues to be under construction, due in part to design modifications, but is currently approved for, and being utilized for slurry disposal. When final construction is completed in 2013 the structure will handle disposal for roughly 36 million clean tons of coal.
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5.
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Current production capabilities are projected to be in the range of 3 to 3.3 million tons per year giving the mine a reserve life of about 15 years. The mine plan is basic room-and-pillar using a synchronized continuous miner section with no retreat mining. Plans are for pillars to be centered on a 60'x80' pattern with 18' entries for our mains, and pillars on 60'x60' centers with 20' entries in the rooms.
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6.
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The Carlisle mine has been in production since February 2007. The North Main, Sub Main #1, and the South Main have been developed with four units currently in production.
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7. The Carlisle mine has two wash plants capable of 950 tons/hour of raw feed.
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Inaccuracies in our estimates of our coal reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.
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Our future performance depends on, among other things, the accuracy of our estimates of our proven and probable coal reserves. We base our estimates of reserves on engineering, economic and geological data assembled, analyzed and reviewed by internal engineers. We update our estimates of the quantity and quality of proven and probable coal reserves annually to reflect the production of coal from the reserves, updated geological models and mining recovery data, the tonnage contained in new lease areas acquired and estimated costs of production and sales prices. There are numerous factors and assumptions inherent in estimating the quantities and qualities of, and costs to mine, coal reserves, including many factors beyond our control, including the following:
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•
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quality of the coal;
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geological and mining conditions, which may not be fully identified by available exploration data and/or may differ from our experiences in areas where we currently mine;
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the percentage of coal ultimately recoverable;
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7
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the assumed effects of regulation, including the issuance of required permits, taxes, including severance and excise taxes and royalties, and other payments to governmental agencies;
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assumptions concerning the timing for the development of the reserves; and
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assumptions concerning equipment and productivity, future coal prices, operating costs, including for critical supplies such as fuel, tires and explosives, capital expenditures and development and reclamation costs.
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As a result, estimates of the quantities and qualities of economically recoverable coal attributable to any particular group of properties, classifications of reserves based on risk of recovery, estimated cost of production, and estimates of future net cash flows expected from these properties as prepared by different engineers, or by the same engineers at different times, may vary materially due to changes in the above factors and assumptions. Actual production recovered from identified reserve areas and properties, and revenues and expenditures associated with our mining operations, may vary materially from estimates.
ITEM 3. LEGAL PROCEEDINGS. None
ITEM 4. MINE SAFETY DISCLOSURES
See Exhibit 95 to this Form 10-K for a listing of our mine safety violations.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Our common stock is traded on the NASDAQ Capital Market under the symbol HNRG. The following table sets forth the high and low closing sales price for the periods indicated:
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High
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Low
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2013
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(January 1 through March 6, 2013)
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$
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8.35
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$
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7.34
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2012
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Fourth quarter
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10.11
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8.03
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Third quarter
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8.51
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7.25
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Second quarter
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9.01
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6.56
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First quarter
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10.83
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8.70
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2011
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Fourth quarter
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10.47
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8.55
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Third quarter
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10.22
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8.25
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Second quarter
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12.05
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9.42
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First quarter
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11.43
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9.79
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Special Cash Dividends
During 2012 we paid three special dividends; April for $.14 per share, August for $.50 and December for $.16 for a total of $.80 per share.
During 2011 we paid one special dividend for $.12 and during 2010 we paid one special dividend for $.10. Over the last three years we have paid out about $30 million in special dividends.
At March 6, 2013, we had 237 shareholders of record of our common stock; this number does not include the shareholders holding stock in "street name.” We estimate we have over 900 street name holders.
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Equity Compensation Plan Information
Restricted Stock Units
At December 31, 2012 we had 481,500 Restricted Stock Units (RSUs) outstanding and 870,000 available for future issuance. The outstanding RSUs have a value of $3.8 million based on our current stock price of $8. During 2011, 30,000 RSUs were granted with cliff vesting over three years; our stock closed at about $11 on grant date. In April 2012, we granted 143,000 RSUs with cliff vesting over three years; our stock closed at $9 on grant date. We expect 315,000 RSUs to vest during 2013 under our current vesting schedule.
During 2012 and 2011, there were 297,500 and 345,000 RSUs that vested each year, respectively. On vesting date the shares had a value of $2.2 million for 2012 and $3.7 million for 2011. Under our RSU plan participants are allowed to relinquish shares to pay for their required minimum statutory income taxes.
Stock based compensation expense for 2012 was $2.7 million and for 2011 was $2.3 million. For 2013 based on existing RSUs outstanding, stock based compensation expense will be $2.2 million.
Stock Options
On January 7, 2011 we allowed four Denver employees (non officers) the opportunity to exchange their remaining vested options (234,167) for 140,000 shares of our common stock. The exchange ratio was based on the intrinsic value of their options. These shares were issued under our Stock Bonus Plan. Under such plan our employees relinquished shares to pay for their required minimum statutory income taxes.
On October 31, 2012 we paid our CEO $1.5 million in exchange for him relinquishing his 200,000 stock options with a $2.30 strike price. The stock was selling for $9.50 on the transaction date. We no longer have any stock options outstanding.
Stock Bonus Plan
Our stock bonus plan was authorized by our BODs in late 2009 with 250,000 shares. As mentioned above under Stock Options, during January 2011, 140,000 shares were issued. Currently, we have about 86,000 shares left in such plan.
ITEM 6. SELECTED FINANCIAL DATA.
Smaller reporting companies are not required to provide the information required by this item.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Our consolidated financial statements should be read in conjunction with this discussion.
Overview
The largest portion of our business is devoted to coal mining in the state of Indiana through Sunrise Coal LLC (a wholly-owned subsidiary) serving the electric power generation industry. We also own a 45% equity interest in Savoy Energy, L.P., a private oil and gas exploration company with operations in Michigan and a 50% interest in Sunrise Energy, LLC, a private gas exploration company with operations in Indiana. We account for our investments in Savoy and Sunrise Energy using the equity method. Historically, through our Denver operations, we also lease oil and gas mineral rights with the intent to sell the prospects to third parties and retain an overriding royalty interest (ORRI) or carried interest. In mid-July 2012 we decided to substantially reduce these activities and our geologist who developed these prospects now works for us on a part-time basis. Further below are discussions of Savoy and our 2011 successful lease play in North Dakota.
Our largest contributor to revenue and earnings is the Carlisle underground coal mine located in western Indiana, about thirty miles south of Terre Haute. The Carlisle mine was in the development stage from April of 2006 through January of 2007. Coal shipments began February 5, 2007. Over 90% of our coal sales are to customers with large scrubbed coal-fired power plants in the state of Indiana. Our mines and coal reserves are strategically located in close proximity to our primary customers, which reduces transportation costs and thus provides us with a competitive advantage with respect to those customers; our closest customer’s plant is 13 miles away and the farthest Indiana customer is 100 miles away. We have access to our primary customers directly through either the CSX Corporation (NYSE: CSX) or through the Indiana Rail Road, majority owned by the CSX.
9
These plants have made or announced plans to make significant investments in pollution control equipment. Due to these large investments none of these plants are scheduled for retirement; thus we expect to be supplying these plants for many years. It is not economical for the smaller, older, less efficient power plants to install scrubbers and other pollution control devices; accordingly, those type plants most likely will be retired in the coming years.
Headwinds and Tailwinds affecting our company:
Headwinds
|
1.
|
Competition from low-priced natgas
|
|
2.
|
The Obama’s administration dislike of burning coal to generate cheap and reliable electricity
|
|
3.
|
Onerous environmental regulations and overzealous mislead environmentalists
|
|
4.
|
Competition from new mines opening in the Illinois Basin
|
|
5.
|
Mild weather
|
|
6.
|
Slow economy
|
Tailwinds
|
1.
|
Illinois Basin (ILB) coal replacing Central Appalachia (CAAP) coal
|
|
2.
|
More power plants are installing scrubbers enabling them to burn high-sulfur coal
|
|
3.
|
Coal can compete with natgas down to $2.75/Mcf
|
|
4.
|
Coal is fastest growing fuel worldwide, thus U.S. exports are increasing rapidly
|
For 2013 we will continue to focus on maintaining our low cost structure and leasing and permitting new reserves.
We see an increasing demand for coal produced in the ILB in the future. Demand for coal produced in the ILB is expected to grow at a rate faster than overall U.S. coal demand, due to ILB coal having higher heating content than Powder River Basin (PRB) and lower cost structure than CAAP coal. Many utilities are scrubbing to meet emission requirements beyond just sulfur compliance, even utilities that burn exclusively PRB. Once scrubbed, those utilities are usually capable of burning ILB coal. It is this trend of new scrubber installations coupled with rising CAAP cost structure that is leading to increased switching from CAAP coal to ILB coal. Some fuel switching will also occur from PRB to ILB in newly scrubbed utilities located near ILB coal supply.
Prospective Information
See page five of this report for a table that illustrates the status of our current coal contracts.
Yorktown Distributions
As previously disclosed, Yorktown Energy Partners and its affiliated partnerships (Yorktown) have made six distributions to their numerous partners totaling 4.5 million (750,000 per distribution) shares since May 2011. In the past these distributions are made soon after we file our Form 10-Qs and Form 10-K. Currently they own about 11 million shares of our stock representing about 39% of total shares outstanding.
We have been informed by Yorktown that they have not made any determination as to the disposition of their remaining Hallador stock. While we do not know Yorktown’s ultimate strategy to realize the value of their Hallador investment for their partners, we expect that over time such distributions will improve our liquidity and float.
If and when we are advised of another Yorktown distribution we will timely report such on a Form 8-K.
Liquidity and Capital Resources
Cash provided by operations was $37 million for 2012. This amount is less than last year due primarily to lower coal sales and payment of income taxes. Our capex budget for 2013 is $27 million. We expect to spend $14 million at the Carlisle mine, of which $3 million is for airshafts, and $5.5 million at the new Ace-in-the-Hole surface mine. The remainder is for other projects.
Funding will come from cash from operations and draws from our new credit facility.
We have no material off-balance sheet arrangements.
10
Special Cash Dividends
During 2012 we paid three special dividends; April for $.14 per share, August for $.50 and December for $.16 for a total of $.80 per share.
During 2011 we paid one special dividend for $.12 and during 2010 we paid one special dividend for $.10. Over the last three years we have paid out $30 million in special dividends.
Projects Update
See pages two-three of this report for a discussion of our current projects.
MSHA Reimbursements
Some of our coal contracts allow us to pass on certain costs incurred resulting from changes in costs to comply with mandates issued by MSHA or other government agencies. In late December 2010, we submitted an analysis of such costs which was reviewed by an outside consulting firm engaged by our customers. In January 2011 the two customers agreed to reimburse us $1.9 million for costs incurred by us during 2008 and 2009. During those years we were not able to accurately estimate what the ultimate outcome of these reimbursable costs would be so we did not record them until we were certain of the amounts and certain of collection. Such amounts were recorded during the first quarter of 2011.
We submitted our incurred costs for 2010 in September of 2011 for $4.2 million. One of our customers agreed with our analysis and paid $2.3 million in February 2012 and the other agreed with our analysis in May 2012. Accordingly, $2.3 million was recorded in the first quarter and the other $1.9 million was recorded in the second quarter of 2012.
We submitted our incurred costs for 2011 in October of 2012 for $4.2 million. We will not recognize any revenue until the customers have notified us that they accept the charges. We were notified in February 2013 that one of the customers is substantially in agreement with our billings; we are still waiting to hear from the other customer. The amount that was agreed upon by the first customer will be recorded in the first quarter of 2013.
2011 North Dakota Lease Play
We invested about $2.5 million in a lease play located in Slope, Hettinger and Stark counties of North Dakota. We sold the property during 2011 and recognized a gain of $10.7 million. We retained a 10% working interest and an approximate 3% average ORRI. If and when a well is proposed, we expect to participate in the drilling.
11
Results of Operations
Quarterly coal sales and cost data (in 000’s):
|
1st
|
2nd
|
3rd
|
4th
|
Year 2012
|
||||||||||||||||
|
Coal sales
|
$
|
29,620
|
$
|
32,487
|
$
|
36,152
|
$
|
33,111
|
$
|
131,370
|
||||||||||
|
Tons sold
|
701
|
743
|
810
|
752
|
3,006
|
|||||||||||||||
|
Average price/ton
|
$
|
42.25
|
$
|
43.72
|
$
|
44.63
|
$
|
44.03
|
$
|
43.70
|
||||||||||
|
Operating costs
|
$
|
18,433
|
$
|
18,816
|
$
|
20,745
|
$
|
21,745
|
$
|
79,739
|
||||||||||
|
Average cost/ton
|
$
|
26.30
|
$
|
25.32
|
$
|
25.61
|
$
|
28.91
|
$
|
26.53
|
||||||||||
|
Margin
|
$
|
11,187
|
$
|
13,671
|
$
|
15,407
|
$
|
11,366
|
$
|
51,631
|
||||||||||
|
Margin/ton
|
$
|
15.96
|
$
|
18.40
|
$
|
19.02
|
$
|
15.11
|
$
|
17.18
|
||||||||||
| Capex | $ | 2,372 | $ | 1,857 | $ | 4,993 | $ | 16,987 | $ | 26,209 | ||||||||||
|
1st
|
2nd
|
3rd
|
4th
|
Year 2011
|
||||||||||||||||
|
Coal sales
|
$
|
33,965
|
$
|
32,136
|
$
|
34,174
|
$
|
37,723
|
$
|
137,998
|
||||||||||
|
Tons sold
|
816
|
765
|
805
|
921
|
3,307
|
|||||||||||||||
|
Average price/ton
|
$
|
41.62
|
$
|
42.01
|
$
|
42.45
|
$
|
40.96
|
$
|
41.73
|
||||||||||
|
Operating costs
|
$
|
18,708
|
$
|
17,902
|
$
|
19,355
|
$
|
21,129
|
$
|
77,094
|
||||||||||
|
Average cost/ton
|
$
|
22.93
|
$
|
23.40
|
$
|
24.04
|
$
|
22.94
|
$
|
23.31
|
||||||||||
|
Margin
|
$
|
15,257
|
$
|
14,234
|
$
|
14,819
|
$
|
16,594
|
$
|
60,904
|
||||||||||
|
Margin/ton
|
$
|
18.70
|
$
|
18.61
|
$
|
18.41
|
$
|
18.02
|
$
|
18.42
|
||||||||||
| Capex | $ | 6,858 | $ | 5,700 | $ | 4,467 | $ | 15,970 | $ | 32,995 | ||||||||||
For 2012, we sold 3,006,000 tons at an average price of $43.70/ton. For 2011 we sold 3,307,000 tons at an average price of $41.73/ton. The warm winter and low natgas prices were the primary reasons our tons sold decreased. Our contracted tons for 2013 are 3.2 million tons at an average price of $40.49.
Operating costs and expenses averaged $26.53/ton in 2012 compared to $23.31 in 2011. The increase was due primarily to poor mining conditions that we experienced during several months of the year. At times we also operated the mine on reduced hours due to lower customer demand, which has a negative effect on productivity which translates to higher costs. As the mine expands our costs will increase as we have more area to maintain. The mine’s mains covered 11.4 miles at December 31, 2012 compared to 9.6 miles at December 31, 2011.
Capex in the fourth quarter of 2012 includes $9 million for the purchase of the Ace-in-the-Hole surface mine and another $4 million for land at Bull Dog and Carlisle. Capex in the fourth quarter of 2011 includes $9 million for the purchase of land for the Bull Dog mine.
Other analyses of results of operations
The decrease in equity income from Savoy was due to higher expenses in all categories plus a nonrecurring expense of $1.4 million for stock based compensation. Further below is a table setting forth Savoy’s operations in more detail for the last two years.
The decrease in equity income from Sunrise Energy was due to lower natgas prices.
The increase in other income is due to higher MSHA reimbursements as more fully explained above under the heading “MSHA Reimbursements.”
The increase in DD&A was due to additions to plant and equipment.
The increase in coal exploration costs relates primarily to higher drilling expense associated with the Bulldog Mine and to new drilling associated with the Russellville reserve.
SG&A increased primarily due to higher expenses associated with the Bulldog Mine and the new Russellville unassigned reserve and 2012 political contributions of $225,000.
12
Income Taxes
Our 2012 effective tax rate was 31% and we expect such rate to be in the 31-33% range for 2013. We estimate that 55% of such rate will be for taxes currently due.
45% Ownership in Savoy
Savoy operates almost exclusively in Michigan. They have an interest in the Trenton-Black River Play in Southern Michigan. They hold 164,000 gross acres (about 82,000 net) in this area. During 2012 Savoy drilled 27 gross wells in this play of which 12 were dry and 15 were successful. During 2013 Savoy plans on drilling 20 or more additional wells in the play. Drilling locations in this play are identified based on the evaluation of extensive 3-D seismic shoots. Savoy operates their own wells and their working interest averages between 40 and 50% and their net revenue interest averages between 34 and 42%. Savoy’s net daily oil production currently averages 910 barrels of oil. Savoy has an interest in about 83 wells (31 net).
The table below provides detail for Savoy’s operations for the last two years; such unaudited amounts are to the 100%, in other words not shown proportionate to our 45% interest (financial statement data in thousands):
|
2012
|
2011
|
|||||||
|
Revenue:
|
||||||||
|
Oil
|
$
|
25,830
|
$
|
25,781
|
||||
|
NGLs (natural gas liquids)
|
926
|
868
|
||||||
|
Gas
|
368
|
566
|
||||||
|
Contract drilling
|
4,555
|
4,336
|
||||||
|
Other
|
373
|
446
|
||||||
|
Total revenue
|
32,052
|
31,997
|
||||||
|
Costs and expenses:
|
||||||||
|
LOE (lease operating expenses)
|
2,659
|
2,257
|
||||||
|
Severance tax
|
2,015
|
2,037
|
||||||
|
Contract drilling costs
|
3,161
|
2,559
|
||||||
|
DD&A (depreciation, depletion & amortization)
|
6,387
|
4,733
|
||||||
|
Geological and geophysical costs
|
3,208
|
1,973
|
||||||
|
Dry hole costs
|
3,244
|
1,852
|
||||||
|
Impairment of unproved properties
|
3,778
|
2,963
|
||||||
|
Other exploration costs
|
340
|
357
|
||||||
|
G&A (general & administrative)
|
1,287
|
1,166
|
||||||
|
Stock option expense
|
1,448
|
|||||||
|
Total expenses
|
27,527
|
19,897
|
||||||
|
Net income
|
$
|
4,525
|
$
|
12,100
|
||||
|
The information below is not in thousands:
|
||||||||
|
Oil production in Bbls
|
295,000
|
283,000
|
||||||
|
4th quarter oil production in Bbls
|
76,000
|
76,600
|
||||||
|
Gas production in Mcf
|
126,000
|
134,500
|
||||||
|
Average oil prices/Bbl
|
$
|
88
|
$
|
91
|
||||
|
Average NGL prices/Bbl
|
$
|
47
|
$
|
62
|
||||
|
Average gas prices/Mcf
|
$
|
2.92
|
$
|
4.20
|
||||
|
Oil reserves in Bbls
|
1,545,000
|
1,921,000
|
||||||
|
NGL reserves in Bbls
|
64,000
|
95,000
|
||||||
|
Gas reserves in Mcf
|
2,448,000
|
2,491,000
|
||||||
|
Oil prices used for SEC PV 10
|
$
|
91
|
$
|
94
|
||||
|
PV 10: proved reserves
|
$
|
78,000,000
|
$
|
97,000,000
|
||||
|
PV 10: proved developed reserves
|
$
|
48,000,000
|
$
|
44,000,000
|
13
Critical Accounting Estimates and Significant Accounting Policies
We believe that the estimates of our coal reserves and our deferred tax assets and liability accounts are our only critical accounting estimates. The reserve estimates are used in the DD&A calculation, in our impairment test and in our internal cash flow projections. If these estimates turn out to be materially under or over-stated; our DD&A expense and impairment test may be affected. Furthermore, if our coal reserves are materially overstated our liquidity and stock price could be adversely affected.
We have analyzed our filing positions in all of the federal and state jurisdictions where we are required to file income tax returns, as well as all open tax years in these jurisdictions. We identified our Federal tax return and our Indiana state tax return as “major” tax jurisdictions. The IRS recently completed an examination of our 2009 and 2010 federal tax returns and there were no significant adjustments. During 2012 the state of Indiana completed their examination of our 2008-2010 returns and no adjustments were proposed. We believe that our income tax filing positions and deductions will be sustained on audit and do not anticipate any adjustments that will result in a material change to our consolidated financial position. Therefore, no reserves for uncertain income tax positions have been recorded.
Our significant accounting policies are set forth in Note 1 to the Financial Statements.
New Accounting Pronouncements
None of the recent FASB pronouncements will have any material effect on us.
Political Contributions
During 2012 we donated $75,000 to the NMA (National Mining Association) Coal Values program which is to help elect pro-coal mining candidates and to promote the use of coal. In April 2012 we made a $100,000 contribution to the Super PAC, Restore our Future (ROF) and in September we made another $50,000 contribution to ROF. We expect such contributions to be minimal for 2013.
In future elections, we encourage all of our shareholders and employees to support those candidates who unequivocally promote legislation and regulations that are favorable to the coal industry.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Smaller reporting companies are not required to provide the information required by this item.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
|
Report of Independent Registered Public Accounting Firm
|
15
|
|
|
Consolidated Balance Sheet
|
16
|
|
|
Consolidated Statement of Comprehensive Income
|
17
|
|
|
Consolidated Statement of Cash Flows
|
18
|
|
|
Consolidated Statement of Stockholders' Equity
|
19
|
|
|
Notes to Consolidated Financial Statements
|
20
|
Smaller reporting companies are not required to provide supplementary data.
14
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Hallador Energy Company
Denver, Colorado
We have audited the accompanying consolidated balance sheet of Hallador Energy Company and Subsidiaries (the “Company”) as of December 31, 2011 and 2012, and the related consolidated statements of comprehensive income, cash flows, and stockholders' equity for each of the years in the two year period ended December 31, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Hallador Energy Company and Subsidiaries, as of December 31, 2011 and 2012, and the results of their operations and their cash flows for each of the years in the two year period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.
/s/ EKS&H LLLP
March 6, 2013
Denver, Colorado
15
I
Consolidated Balance Sheet
As of December 31,
(in thousands, except per share data)
|
ASSETS
|
2012
|
2011
|
||||||
|
Current assets:
|
||||||||
|
Cash and cash equivalents
|
$
|
21,888
|
$
|
37,542
|
||||
|
Accounts receivable
|
8,127
|
6,689
|
||||||
|
Coal inventory
|
2,342
|
1,863
|
||||||
|
Parts and supply inventory
|
2,264
|
2,202
|
||||||
|
Other
|
242
|
580
|
||||||
|
Total current assets
|
34,863
|
48,876
|
||||||
|
Coal properties, at cost:
|
||||||||
|
Land and mineral rights
|
22,705
|
16,465
|
||||||
|
Buildings and equipment
|
131,566
|
121,242
|
||||||
|
Mine development
|
71,046
|
66,614
|
||||||
|
225,317
|
204,321
|
|||||||
|
Less - accumulated DD&A
|
(58,479
|
)
|
(42,493
|
)
|
||||
|
166,838
|
161,828
|
|||||||
|
| ||||||||