UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K

[ x ]ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the fiscal year ended: December 31, 20122013       OR
 
[  ]
TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 0-14731

“COAL KEEPS YOUR LIGHTS ON”
“COAL KEEPS YOUR LIGHTS ON”
HALLADOR ENERGY COMPANY
(www.halladorenergy.com)
 
COLORADO
(State of incorporation)
 
84-1014610
(IRS Employer Identification No.)
 
1660 Lincoln Street, Suite 2700, Denver, Colorado
(Address of principal executive offices)
 
80264-2701
(Zip Code)
  
Issuer's telephone number: 303.839.5504    

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. oþ

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.

o Large accelerated filer
o Accelerated filer
o Non-accelerated filer (do not check if a small reporting company)
þ Smaller reporting company

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, 20122013 was $64$74 million based on the closing price reported that date by the NASDAQ of $8.48$8.05 per share.

As of March 6, 20132014 we had 28.528.7 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, 201324, 2014 are incorporated by reference into Part III of this Form 10-K.

 
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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 areSee Item 7- MDA for a Colorado corporation organized by our predecessor in 1949.  70%discussion 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.business.

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)Regulatory Matters
 
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:
·  
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.
·  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.

·  
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.
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):
    Year End Reserves 
  Annual Capacity 2012 2011 
        
Carlisle (assigned)
 
3.3
 
  43.5
 
46.0
 
Ace-in-the-Hole (assigned)   .5     3.1 - 
Bulldog (unassigned)
 
-
 
  35.6
 
32.3
 
Russellville (unassigned) -   29.4 -��
  Total
 
3.8
 
111.6 
 
78.3
 
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:
Year Contracted Tons Average Price/Ton 
      
2013
 
3,221,000
 
$40.49
 
2014 1,700,000 $45.01 
Total
 
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.

ReclamationFederal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, the reclamation and restoration of mining properties after mining has been completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects of mining on groundwater quality and availability. In addition, the industry is affected by significant legislation mandating certain benefits for current and retired coal miners. Numerous federal, state and local governmental permits and approvals are required for mining operations. We believe that we have obtained all permits currently required to conduct our present mining operations.
We endeavor to conduct our mining operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time in the industry. None of our violations to date or the monetary penalties assessed have been material.
Mine Safety and Health
We are subject to health and safety standards both at the federal and state level. The regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters.
Mine Safety and Health Administration (MSHA) is the entity responsible for monitoring compliance with the federal mine health and safety standards. MSHA has various enforcement tools that it can use, including the issuance of monetary penalties and orders of withdrawal from a mine or part of a mine. Some, but not all, of the costs of complying with existing regulations and implementing new safety and health regulations may be passed on to customers.

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MSHA has taken a number of actions to identify mines with safety issues, and has engaged in a number of targeted enforcement, awareness, outreach and rulemaking activities to reduce the number of mining fatalities, accidents and illnesses. There has also been an industry-wide increase in the monetary penalties assessed for citations of a similar nature.
Black Lung
Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each U.S. coal mine operator must pay federal black lung benefits and medical expenses to claimants who are current and former employees and last worked for the operator after July 1, 1973. Coal mine operators must also make payments to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. Historically, less than 7% of the miners currently seeking federal black lung benefits are awarded these benefits. The trust fund is funded by an excise tax on U.S. production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.
Environmental Laws and Regulations
We are subject to various federal, state and local environmental laws and regulations. These laws and regulations place substantial requirements on our coal mining operations, and require regular inspection and monitoring of our mines and other facilities to ensure compliance. We are also affected by various other federal, state and local environmental laws and regulations that our customers are subject to.
Surface Mining Control and Reclamation Act. In the U.S., the Surface Mining Control and Reclamation Act of 1977 (SMCRA), which is administered by the Office of Surface Mining Reclamation and Enforcement (OSM), established mining, environmental protection and reclamation standards for all aspects of U.S. surface mining and many aspects of deep mining. Mine operators must obtain SMCRA permits and permit renewals for mining operations from the OSM. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the regulatory authority.
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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After a permit application is prepared and submitted to the regulatory agency, it goes through a completeness and technical review. Public notice of the proposed permit is given for a comment period before a permit can be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has the right to comment on and otherwise engage in the permitting process, including public hearings and through intervention in the courts. Before a SMCRA permit is issued, a mine operator must submit a bond or other form of financial security to guarantee the performance of reclamation obligations.
The SMCRA Abandoned Mine Land Fund requires a fee on all coal produced in the U.S. The proceeds are used to rehabilitate lands mined and left unreclaimed prior to August 3, 1977 and to pay health care benefit costs of orphan beneficiaries of the Combined Fund created by the Coal Industry Retiree Health Benefit Act of 1992. The fee amount can change periodically. Pursuant to the Tax Relief and Health Care Act of 2006, from October 1, 2007 to September 30, 2012, the fee was $0.315 and $0.135 per ton of surface-mined and underground-mined coal, respectively. From October 1, 2012 through September 30, 2021, the fee is $0.28 and $0.12 per ton of surface-mined and underground-mined coal, respectively. We also pay $0.03 per ton to the Indiana Department of Reclamation.
The OSM has been in the process of developing a “stream protection rule,” which could result in changes to mining operations under the SMCRA program. The OSM has projected that it will issue a proposed stream protection rule in 2014. Other rulemaking proceedings have been proposed or are being considered by the OSM. Notably, the Proposed Rule for Cost Recovery for Permit Processing, Administration and Enforcement was published in March 2013.   Additionally, the OSM is working on a Coal Combustion Residues rulemaking for minefill operations. The agency has projected it may publish a proposed rule by May 2014. These OSM rulemakings and others could have a direct impact on our operations.
Clean Air Act. The Clean Air Act, enacted in 1970, and comparable state laws that regulate air emissions affect our U.S. coal mining operations both directly and indirectly.
Direct impacts on coal mining and processing operations may occur through the Clean Air Act permitting requirements and/or emission control requirements relating to particulate matter (PM), sulfur dioxide and ozone. It is possible that modifications to the national ambient air quality standards (NAAQS) could directly impact our mining operations in a manner that includes, but is not limited to, requiring changes in vehicle emissions standards or resulting in newly designated non-attainment areas. Furthermore, the U.S. Environmental Protection Agency (EPA) in 2009 adopted revised rules to add more stringent PM emissions limits for coal preparation and processing plants constructed or modified after April 28, 2008. Since 2011, the EPA has required underground coal mines to report on their greenhouse gas emissions.
The Clean Air Act indirectly, but more significantly, affects the U.S. coal industry by extensively regulating the air emissions of sulfur dioxide, nitrogen oxides, mercury, PM and other substances emitted by coal-fueled electricity generating plants. The air emissions programs that may affect our operations, directly or indirectly, include, but are not limited to, the Acid Rain Program, interstate transport rules, New Source Performance Standards (NSPS), Maximum Achievable Control Technology (MACT) emissions limits for Hazardous Air Pollutants, the Regional Haze program and New Source Review.  In addition, in recent years the U.S. EPA has adopted more stringent NAAQS for PM, nitrogen oxide and sulfur dioxide.  The EPA is expected to propose a more stringent ozone standard from the current standard. The Sierra Club and others requested the U.S. District Court for the Northern District of California on January 21, 2014 to order the EPA to propose a new ozone NAAQS by December 1, 2014 and issue a final rule by October 1, 2015. The actual final rule date remains unknown at this time. More stringent standards may trigger additional control technology for mining equipment, or result in additional challenges to permitting and expansion efforts. Many of these air emissions programs and regulations have resulted in litigation which has not been completely resolved.

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In December 2009, the EPA published its finding that atmospheric concentrations of greenhouse gases endanger public health and welfare within the meaning of the Clean Air Act, and that emissions of greenhouse gases from new motor vehicles and motor vehicle engines are contributing to air pollution that are endangering public health and welfare within the meaning of the Clean Air Act. In May 2010, the EPA published final greenhouse gas emission standards for new motor vehicles pursuant to the Clean Air Act.  Both the endangerment finding and motor vehicle standards have been the subject of litigation. Because the Clean Air Act specifies that the prevention of significant deterioration (PSD) program applies once emissions of regulated pollutants exceed either 100 or 250 tons per year (depending on the type of source), millions of sources previously unregulated under the Clean Air Act could be subject to greenhouse gas reduction measures.  The EPA published a rule in June 2010 to limit the number of greenhouse gas sources that would be subject to the PSD program.  In the so-called “tailoring rule,” the EPA limited the regulation of greenhouse gases from certain stationary sources to those that emit more than 75,000 tons of greenhouse gases per year (for sources that would be subject to PSD permitting regardless of greenhouse gas emissions due to other emissions) or 100,000 tons of greenhouse gases per year (for sources not subject to PSD permitting for any other air emissions), measured by “carbon dioxide equivalent.”
In a decision issued on June 26, 2012, the U.S. Court of Appeals for the District of Columbia (D.C. Circuit) affirmed the EPA's endangerment finding, its motor vehicle greenhouse gas rule and the tailoring rule.  In a decision issued on December 20, 2012, the same court denied petitions to reconsider that decision. Petitions for review to the U.S. Supreme Court (Supreme Court) were filed, and on October 15, 2013, the Supreme Court accepted six petitions for review, but only a single question is being considered: “Whether the EPA permissibly determined that its regulation of greenhouse gas emissions from new motor vehicles triggered permitting requirements under the Clean Air Act for stationary sources that emit greenhouse gases.” A decision in the case will likely come by June 2014. This review will not affect the D.C. Circuit decision upholding the EPA’s 2009 “endangerment finding” with respect to greenhouse gas emissions from new motor vehicles. However, the decision could have a significant impact on EPA rules, proposed rules and rules under development that may affect the demand for coal, including the proposed NSPS for carbon dioxide emissions from new fossil fuel-fired electric utility generating units and the performance standards under development for carbon dioxide emissions from existing power plants.
Proposed NSPS for Fossil Fuel-Fired Electricity Utility Generating Units. On April 13, 2012, the EPA published for comment proposed NSPS for emissions of carbon dioxide from new fossil fuel-fired electric utility generating units. If those standards are adopted as proposed, it is unlikely, with a few possible exceptions, that any new coal-fired electric utility generating units could be constructed in the U.S. as CCS technologies are not yet commercially viable.
In light of over 2 million comments on its April 13, 2012 proposal and ongoing developments in the industry, the EPA subsequently indicated its intention to issue a new proposal. On June 25, 2013, the U.S. President directed the EPA to issue that new proposal by September 30, 2013 and to finalize it in a timely manner. On September 20, 2013, the EPA revoked its April 13, 2012 proposal and issued a new proposed NSPS for emissions of carbon dioxide from new fossil fuel-fired electric utility generating units, using section 111(b) of the Clean Air Act. On January 8, 2014, the re-proposal was published in the Federal Register, with the comment deadline stated as March 10, 2014.
The EPA has not yet proposed rules for modified sources under section 111(b) of the Clean Air Act or existing sources under section 111(d) of the Clean Air Act. However, the U.S. President directed the EPA, in the June 25, 2013 statement referred to above, to issue such standards, regulations or guidelines, as appropriate, addressing carbon pollution from existing, modified and reconstructed power plants. The President also requested that the EPA: (a) issue a proposal addressing such matters by June 1, 2014; (b) finalize it by June 1, 2015; and (c) include, in the guidelines addressing existing power plants, a requirement that states submit to the EPA implementation plans required under Section 111(d) of the Clean Air Act by June 30, 2016. We believe that any final rules issued by the EPA in this area will be challenged.

 
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Mine HealthCross State Air Pollution Rule (CSAPR). On July 6, 2011, the EPA finalized the CSAPR, which requires 28 states from Texas eastward (not including the New England states or Delaware) to significantly improve air quality by reducing power plant emissions that cross state lines and Safety Laws

Wecontribute to ozone and/or fine particle pollution in other states. Under the CSAPR, the first phase of the nitrogen oxide and sulfur dioxide emissions reductions was to commence in 2012 with further reductions effective in 2014. In October 2011, the EPA proposed amendments to the CSAPR to increase emission budgets in ten states, including Texas, and ease limits on market-based compliance options. While the CSAPR had an initial compliance deadline of January 1, 2012, the rule was challenged and on December 30, 2011, the D.C. Circuit stayed the rule and advised that the EPA is expected to continue administering the Clean Air Interstate Rule (CAIR) until the pending challenges are proudresolved. The court vacated the CSAPR on August 21, 2012, in a 2 to 1 decision, concluding that the rule was beyond the EPA's statutory authority. On October 5, 2012, the EPA petitioned for en banc review of our safety record.  We complythat decision by the entire D.C. Circuit, which denied the EPA's petition on January 24, 2013. On March 29, 2013, the Solicitor General's Office, on behalf of the EPA, and, separately, certain non-governmental organizations, filed petitions for writs of certiorari with the rulesSupreme Court seeking Supreme Court review of the D.C. Circuit's decision. The Supreme Court granted these petitions on June 24, 2013, held oral arguments on December 10, 2013 and regulation issuedwill likely issue a decision 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.June 2014.
 
CleanMercury and Air ActToxic Standards (MATS). On December 16, 2011, the EPA issued MATS, which imposes MACT emission limits on hazardous air emissions from new and Related Regulationsexisting coal-fueled electric generating plants. The rule also revised NSPS for nitrogen oxides, sulfur dioxides and particulate matter for new and modified coal-fueled electricity generating plants. The MACT rule provides three years for compliance and a possible fourth year as a state permitting agency may deem necessary. On March 28, 2013, the EPA issued reconsidered MACT standards for new plants that are less stringent in some aspects than the standards issued in December 2011. On June 24, 2013, certain environmental organizations and industry groups filed an appeal of these regulations in the D.C. Circuit, and oral arguments were held on December 10, 2013. The rule could result in the retirement of certain older coal plants.
 
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.
Water Act. The Clean AirWater Act also indirectly affectsof 1972 directly impacts U.S. coal mining operations by extensively regulatingrequiring effluent limitations and treatment standards for wastewater discharge from mines through the air emissionsNational Pollutant Discharge Elimination System (NPDES). Regular monitoring, reporting and performance standards are requirements of NPDES permits that govern the discharge of water from mine-related point sources into receiving waters.
The U.S. Army Corps of Engineers (Corps) regulates certain activities affecting navigable waters and waters of the coal-fired electric power generating plants operatedU.S., including wetlands. Section 404 of the Clean Water Act requires mining companies to obtain Corps permits to place material in streams for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities.
States are empowered to develop and apply “in stream” water quality standards. These standards are subject to change and must be approved by our customers. Coal contains impurities,the EPA. Discharges must either meet state water quality standards or be authorized through available regulatory processes such as sulfur, mercuryalternate standards or variances. “In stream” standards vary from state to state. Additionally, through the Clean Water Act section 401 certification program, states have approval authority over federal permits or licenses that might result in a discharge to their waters. States consider whether the activity will comply with their water quality standards and other constituents, manyapplicable requirements in deciding whether or not to certify the activity.
In September 2013, a draft rule identifying waters protected by the Clean Water Act was sent to the Office of Management and Budget. This draft rule may be formally proposed by the EPA in early 2014, but we believe the final rule will not likely be issued until 2015. Litigation is likely from various stakeholders. If CWA authority is eventually expanded, it may impact our operations in some areas by way of additional requirements.

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National Environmental Policy Act (NEPA). NEPA, signed into law in 1970, requires federal agencies to review the environmental impacts of their decisions and issue either an environmental assessment or an environmental impact statement. We must provide information to agencies when we propose actions that will be under the authority of the federal government. The NEPA process involves public participation and can involve lengthy timeframes.
Resource Conservation and Recovery Act (RCRA). RCRA, which was enacted in 1976, affects U.S. coal mining operations by establishing “cradle to grave” requirements for the treatment, storage and disposal of hazardous wastes. Typically, the only hazardous wastes generated at a mine site are releasedthose from products used in vehicles and for machinery maintenance. Coal mine wastes, such as overburden and coal cleaning wastes, are not considered hazardous wastes under RCRA.
Subtitle C of RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. A recent federal district court decision in the District of Columbia requires the EPA to soon submit to the court a proposed deadline for completing the agency’s CCR rulemaking process. This EPA initiative is separate from the OSM CCR rulemaking mentioned above.
Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). Although typically not applied to the coal mining sector, CERCLA, which was enacted in 1980, nonetheless may affect U.S. coal mining operations by creating liability for investigation and remediation in response to releases of hazardous substances into the air when coalenvironment and for damages to natural resources. Under CERCLA, joint and several liabilities may be imposed on waste generators, site owners or operators and others, regardless of fault.
Toxic Release Inventory. Arising out of the passage of the Emergency Planning and Community Right-to-Know Act in 1986 and the Pollution Prevention Act passed in 1990, the EPA's Toxic Release Inventory program requires companies to report the use, manufacture or processing of listed toxic materials that exceed established thresholds, including chemicals used in equipment maintenance, reclamation, water treatment and ash received for mine placement from power generation customers.
Endangered Species Act (ESA). The ESA of 1973 and counterpart state legislation is burned. Carbon dioxide,intended to protect species whose populations allow for categorization as either endangered or threatened. Changes in listings or requirements under these regulations could have a material adverse effect on our our costs or our ability to mine some of our properties in accordance with our current mining plans.
Use of Explosives. Our surface mining operations are subject to numerous regulations relating to blasting activities. Pursuant to these regulations, we incur costs to design and implement blast schedules and to conduct pre-blast surveys and blast monitoring. The storage of explosives is subject to strict federal regulatory requirements. The U.S. Bureau of Alcohol, Tobacco and Firearms (ATF) regulates the use of explosive blasting materials. In addition to ATF regulation, the Department of Homeland Security (DHS) is expected to finalize an ammonium nitrate security program rule in 2014. While such new regulations may result in additional costs related to our surface mining operations, such costs are not expected to have a material adverse effect on our results of operations, financial condition or cash flows.
Global Climate
In the U.S., Congress has considered legislation addressing global climate issues and greenhouse gas (GHG),emissions, but to date nothing has been enacted. While it is also emitted when coalpossible that the U.S. will adopt legislation in the future, the timing and specific requirements of any such legislation are uncertain. In the absence of new U.S. federal legislation, the EPA is burned. Environmental regulations governingundertaking steps to regulate greenhouse gas emissions pursuant to the Clean Air Act. In response to the 2007 U.S. Supreme Court ruling in Massachusetts v. EPA, the EPA has commenced several rulemaking projects as described under “Regulatory Matters-U.S. - Clean Air Act.”
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A number of states in the U.S. have adopted programs to regulate greenhouse gas emissions. For example, 10 northeastern states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont) entered into the Regional Greenhouse Gas Initiative (RGGI) in 2005, which is a mandatory cap-and-trade program to cap regional carbon dioxide emissions from coal-fired electric generatingpower plants. In 2011, New Jersey announced its withdrawal from RGGI effective January 1, 2012. Six midwestern states (Illinois, Iowa, Kansas, Michigan, Minnesota and Wisconsin) and one Canadian province have entered into the Midwestern Regional Greenhouse Gas Reduction Accord (MGGRA) to establish voluntary regional greenhouse gas reduction targets and develop a voluntary multi-sector cap-and-trade system to help meet the targets. It has been reported that, while the MGGRA has not been formally suspended, the participating states are no longer pursuing it. Seven western states (Arizona, California, Montana, New Mexico, Oregon, Utah and Washington) and four Canadian provinces entered into the Western Climate Initiative (WCI) in 2008 to establish a voluntary regional greenhouse gas reduction goal and develop market-based strategies to achieve emissions reductions. However, in November 2011, the WCI announced that six states had withdrawn from the WCI, leaving California and four Canadian provinces as the remaining members. Of those five jurisdictions, only California and Quebec have adopted greenhouse gas cap-and-trade regulations to date and both programs have begun operating. Many of the states and provinces that left WCI, RGGI and MGGRA, along with many that continue to participate, have joined the new North America 2050 initiative, which seeks to reduce greenhouse gas emissions and create economic opportunities in ways not limited to cap-and-trade programs.
In the U.S., several states have enacted legislation establishing greenhouse gas emissions reduction goals or requirements. In addition, several states have enacted legislation or have in effect regulations requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power or that provide financial incentives to electricity suppliers for using renewable energy sources.
In 2013, the U.S. and a number of international development banks, including the World Bank, the European Investment Bank and the European Bank for Reconstruction and Development, announced that they would no longer provide financing for the development of new coal-fueled power plants or would do so only in narrowly defined circumstances. Other international development banks, such as the Asian Development Bank, have indicated that they will continue to provide such financing.
The Kyoto Protocol, adopted in December 1997 by the signatories to the 1992 United Nations Framework Convention on Climate Change, established a binding set of emission targets for developed nations. The U.S. signed the Kyoto Protocol but it was not ratified by the U.S. Senate. Australia ratified the Kyoto Protocol in December 2007 and became a full member in March 2008. There are continuing discussions to develop a treaty to replace the Kyoto Protocol after its expiration in 2012, including at the Cancun meetings in late 2010, the Durban meeting in late 2011 and the Doha meeting in late 2012. At the Doha meeting, an amendment to the Kyoto Protocol was adopted, which includes new commitments for certain parties in a second commitment period, from 2013 to 2020.
Enactment of laws or passage of regulations regarding emissions from the combustion of coal by the U.S., some of its states or other countries, or other actions to limit such emissions, could result in electricity generators switching from coal to other fuel sources. Further, policies limiting available financing for the development of new coal-fueled power plants could affectadversely impact the global demand for coal in the future. The potential financial impact on us of future laws, regulations or other policies will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance on coal as a fuel sourcesource. That, in turn, will depend on a number of factors, including the specific requirements imposed by any such laws, regulations or other policies, the time periods over which those laws, regulations or other policies would be phased in, the state of commercial development and affectdeployment of CCS technologies and the volumealternative markets for coal. In view of the significant uncertainty surrounding each of these factors, it is not possible for us to reasonably predict the impact that any such laws, regulations or other policies may have on our results of operations, financial condition or cash flows.

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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 sales. For example,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 federalearly 1990s, as greater environmental accountability was established in the electric utility industry.  Through the U.S. Clean Air Act, places limits onacceptable baseline levels were established for the release of sulfur dioxide nitrogen 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 mercury emissions from electric power plants.has enabled them to burn lower cost, high sulfur coal.
 
The installationILB consists of additional control measurescoal 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 achieve regulatory emission reductions makes it more costly to operatesufficient 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 could make coal a less attractive fuel.Middle Atlantic.
 
OtherU. 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 have no significant patents, trademarks, licenses, franchises or concessions.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 370 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. All of our mines are non-union.  Other than the 330370 Sunrise Coal employees in Indiana, our CEO,Chairman, CFO, controller, land person and two part time administrative staff work in the Denver office.

Other
We have no significant patents, trademarks, licenses, franchises or concessions.
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.comand 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.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 - threeItem 7 MDA  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 threefive 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.
For the exploration process core samples are bagged and boxed and delivered to an independent lab for analysis.  For the production process samples are taken just before the coal is placed in the rail car by the customer and delivered to an independent lab for analysis.
Prior to acquiring coal leases, we have our title abstractors or contract title abstractors conduct a preliminary title search on the property.  This information provides a strong indication of the coal owner, with whom we will enter into a lease. The next step is to execute a lease with the owner, giving us control of the property.  Prior to mining the coal, we verify the lessor is the coal owner with a title opinion.  Prior to purchasing coal properties we follow a similar process.

ADDITIONAL DISCLOSURES FOR THE CARLISLE MINE

1.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.

2.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.

3.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, known as the “main fans”, at the base of the slope for mine ventilation.  Two additional air shafts (8’ and 10.5’ diameter), known as the “north fans”, 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.  Two additional 8’ diameter airshafts, the “north portal fans”, were completed in 2013 at the North Portal facility to more effectively ventilate the north units, and facilitate more efficient use of the main set and north set of air shafts to units elsewhere in the mine.   All underground mining equipment is powered with electricity and underground compliant diesel.

4.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 ishas been completed in 2013 the structure will handleas planned.  The impoundment is currently being utilized as fine refuse disposal, for roughlywith a final estimated storage capacity of 36 million clean tons of coal.tons.

5.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.

6.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.

7.      The Carlisle mine has two wash plants capable of 950 tons/hour of raw feed.


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The Ace-in-the-Hole mine is a multi-seam open pit strip mine. The majority of the seams are sold raw, but some of the seams will be washed prior to sales depending on quality. To convert the tons sold raw the in-place tonnage is taken times a pit recovery of 94% based on seam thickness. To convert the tons sold washed the in-place tonnage is taken times a pit recovery based on seam thickness then reduced by the projected plant recovery of 72%.

Mine and Wash Plant Recovery

  Mine recovery Wash plant recovery 
Carlisle 53% 69-72% 
Bulldog 45% 77% 
Russellville 54% 77% 

Inaccuracies in our estimates of our coal reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.

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:
   
 • quality of the coal;
   
 • 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;
   
 • the percentage of coal ultimately recoverable;
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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;
   
 • assumptions concerning the timing for the development of the reserves; and
   
 • 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.
 
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.
 
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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.
 
Stock Price Information
Our common stock is traded on the NASDAQ Capital Market under the symbol HNRG.  64% of our stock is held by our officers, directors and their affiliates. The following table sets forth the high and low closing sales price for the periods indicated:
 
 High Low   High Low 
2014     
January 1 through March 5, 2014 $8.29  $7.63   
2013             
(January 1 through March 6, 2013) $8.35 $7.34  
Fourth quarter 8.55 6.58 
Third quarter 8.41 6.82 
Second quarter 8.37 6.46 
First quarter 8.35 6.90 
2012             
Fourth quarter  10.11  8.03   10.11   8.03 
Third quarter  8.51  7.25   8.51 7.25 
Second quarter  9.01  6.56   9.01 6.56 
First quarter  10.83  8.70   10.83   8.70 
2011        
Fourth quarter  10.47  8.55  
Third quarter  10.22  8.25  
Second quarter  12.05  9.42  
First quarter  11.43  9.79  

Regular and Special Cash Dividends

On April 5, 2013 our Board of Directors approved the adoption of a regular quarterly dividend policy. During 2013 we paid three regular quarterly dividends of $.04 each on May 15, August 15 and November 15.

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, 2013,5, 2014, we had 237236 shareholders of record of our common stock; this number does not include the shareholders holding stock in "street name.”  We estimate we have over 9001,800 street name holders.
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Equity Compensation Plan Information

Restricted Stock Units

At December 31, 20122013 we had 481,500164,000 Restricted Stock Units (RSUs) outstanding and 870,000840,000 available for future issuance.  The outstanding RSUs have a value of $3.8$9 million based on our current stock price of $8.  During 2011, 30,000$8.21.  On February 1, 2014 we granted 920,000 RSUs were granted with cliff vestingto key employees of which 720,000 vest equally over threefour years and 200,000 vest equally over two years; our stock closed at about $11price on grant date.date was $7.66 per share.  In April 2012, we granted 143,000 RSUs with cliff vesting over three years; our stock closed at $9 on grant date.  We expect 315,000310,000 RSUs to vestvest/lapse during 20132014 under our current vesting schedule.

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During 20122013 and 2011,2012, there were 297,500315,500 and 345,000297,500 RSUs that vested, each year, respectively.  On the vesting datedates the shares had a value of $2.2$2.3 million for 20122013 and $3.7$2.4 million for 2011.2012.  Under our RSU planPlan participants are allowed to relinquish shares to pay for their required minimum statutory income taxes.

Stock basedStock-based compensation expense for 2013 was $2.2 million and for 2012 was $2.7 million and for 2011 was $2.3 million.  For 20132014, based on existing RSUs outstanding, stock basedstock-based compensation expense will be $2.2$2.7 million.
Stock Options

On January 7, 2011 we allowed four Denver employees (non officers)February 1, 2014, our Board of Directors authorized to increase the opportunity to exchange their remaining vested options (234,167)available shares for 140,000 shares of our common stock. The exchange ratio was based onissuance under the intrinsic value of their options.  These shares were issued under our2008 Restricted Stock Bonus Plan.  Under such plan our employees relinquishedUnit Plan by 1,500,000 shares to paybe used for their required minimum statutory income taxes.future compensation.  The total number of RSUs authorized under the plan since inception is 3,850,000.

Stock Options

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 thirty30 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%81% 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.
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These plants have made or announced plans  During 2013 about 12% of our sales were to make significant investmentscustomers 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.Central Florida almost 1,000 miles away.

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 ILBIllinois Basin (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 CAAPCentral Appalachia (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
14
Our customers have made or announced plans to make significant investments in pollution control equipment at their plants.  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.

See page fiveOur Coal Contracts

We have close relationships with our customers: Duke Energy Corporation (NYSE:DUK), Hoosier Energy, an electric cooperative, and Indianapolis Power & Light Company, a wholly-owned subsidiary of this report for aThe AES Corporation (NYSE:AES). During 2013 and 2012 we sold 400,600 tons and 185,000 tons, respectively to an Orlando utility through an arrangement we have with an affiliate of JP Morgan. We believe these Florida sales are an indication of the trend of ILB coal replacing CAAP coal that has traditionally supplied the southeast markets.  During 2013 we sold about one million tons each to two customers, about 500,000 tons to the third customer and about 400,000 tons to the fourth customer.

The table thatbelow illustrates the status of our current coal contracts.contracts:
Year Contracted Tons Average Price/Ton 
      
2014
 
 3,504,000*       
 
 $42.72   
 
 2015 1,650,000 41.99 
 2016    689,000  40.93 **.
    Total
 
5,843,000       
   
_________________________
*Includes about 150,000 tons from our new Ace-in-the-Hole surface mine.

Yorktown Distributions**During 2013, to accommodate one of our major customers, we entered into three separate agreements that allowed them to defer 338,000 tons originally to be delivered in 2013 to sometime in 2016. Under the agreements they agreed to pay us an average of $5.36/ton over the life of the deferral periods and we recognize the revenue accordingly as required by US GAAP. Therefore, we recognized $251,000 in the fourth quarter of 2013 and will recognize $781,000 during each of the years 2014 and 2015; otherwise our average price/ton in 2016 would be $43.57.
We expect to continue selling a significant portion of our coal under supply agreements with terms of one year or longer. 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.

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 sharesCurrent Projects

All of our stock representing about 39%underground coal reserves are high sulfur (4.5 - 6#) with a BTU content in the 11,500 range. As discussed below, the Ace surface mine is low sulfur (1.5#) with a BTU content of total shares outstanding.11,400.  We have no met coal reserves, only steam (thermal) coal reserves. We do not use outside contractors. Below is a discussion of our current projects preceded by a table of our coal reserves.

15
Reserve Table - Controlled Tons (in millions):

    Year-End Reserves
  Annual Capacity 2013 2012
    Proven Probable Total Proven Probable Total
               
Carlisle (assigned) 3.4 33.5 8.6 42.1 34.2 9.3 43.5
Ace-in-the-Hole (assigned) 0.5 3.1   3.1 3.1   3.1
Bulldog (unassigned)   19.6 16.2 35.8 19.5 16.1 35.6
War Eagle (unassigned)   27.7 15.4 43.1 15.5 13.9 29.4
  Total 3.9 83.9 40.2 124.1 72.3 39.3 111.6
               
Assigned       45.2     46.6
Unassigned         78.9     65.0
         124.1     111.6
Active Reserve (assigned) - Carlisle Mine (underground)
Our coal reserves at December 31, 2013 assigned to the Carlisle Mine were 42.1 million tons compared to beginning of year reserves of 43.5 million tons.  Primarily through the execution of new leases, our reserve additions of 2.5 million tons replaced 80% of our 2013 production of 3.1 million tons. We reduced our reserves by 810,000 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:
SO2 - Historically, Carlisle has guaranteed a 6# SO2 product; however, with the addition of the Ace-in-the-Hole Mine we can blend lower sulfur coal with Carlisle coal and guarantee a mid-sulfur product which should command a higher price and increase our customer base.  Few mines in the ILB have the ability to offer their customers various ranges of SO2. Carlisle has supplied coal to 11 different power plants.  
• Chlorine - Our reserves have lower chlorine (<0.10%) than average ILB reserves 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.

• 
Transportation - Carlisle 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.

16
New Mine (assigned) - Ace-in-the-Hole Mine (Ace) (surface)
In November 2012 we purchased for $6 million permitted fee coal reserves, coal leases and surface properties near Clay City, Indiana in Clay County.  The Ace 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 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 began shipping coal in late August 2013.  We 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 ILB (6# SO2). Blending Carlisle coal to a lower sulfur specification enables us to market Carlisle coal to more customers.  We currently have a contract at Carlisle which requires 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 30% of its capacity contracted for 2014.  We have invested $22 million in minerals, land, equipment and development as of December 31, 2013.

During the last half of 2013 we sold 10,000 high sulfur and 26,000 low sulfur tons from Ace.  Ace transitioned to the production stage in October.

New Reserve (unassigned) - Bulldog Mine (underground)
 
We have been informed by Yorktownleased roughly 19,300 acres in Vermillion County, Illinois near the village of Allerton.  Based on our reserve estimates we currently control 35.8 million tons of coal reserves. 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 2014.  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 fourth quarter of 2014.
Full-scale mine development will not commence until we have a sales commitment. We estimate the costs to develop this mine to be $150 million at full capacity of three million tons annually.
New Reserve (unassigned) – War Eagle Mine (underground)
We have leased roughly 11,000 acres in Lawrence County, Illinois near the village of Russellville. Based on our reserve estimates we currently control 43.1 million tons of coal reserves. This reserve is located about 20 miles southwest of the Carlisle Mine. Our initial testing indicates that they have not made any determination asthis reserve’s minability and coal quality is very similar to the dispositionCarlisle reserve.

We anticipate filing for a mining permit in late 2014. Full-scale mine development will not commence until we have a sales commitment. We estimate the costs to develop this mine to be $150 million at full capacity of their remaining Hallador stock. While3.3 million tons annually.

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.

17


Below is a map that shows our mines, reserves and customer (past and present) locations.
18

On May 31, 2013 we purchased for $2.8 million a multi-commodity truck/barge terminal. Over 17 acres of secured area is available. The terminal is at mile point 743.8 on the Indiana bank of the Ohio River near the William Natcher Bridge between Rockport and Grandview, Indiana.  Currently the dock will handle third party commodities.  In the long term, we plan to ship coal through the dock.  The terminal is in close proximity to the NS railroad, the CSX railroad and American Electric Power's Rockport generating power plant. We do not know Yorktown’s ultimate strategy to realize the value of their Hallador investmentexpect revenue from this asset until 2015. G&A expenses for their partners, we expect that over time such distributions will improve our liquidity and float.this property were about $500,000 during 2013.
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 20132014 is $27about $15 million.  WeAt Carlisle we expect to spend $14$12 million at the Carlisle mine, of which $3for maintenance capex and $2.5 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 cashexpansion capex.  At Ace we estimate maintenance capex to be about $500,000. Cash from operations and draws fromshould fund these expenditures. In addition we have about $110 million available under our new credit facility.bank line.

We have no material off-balance sheet arrangements.

Capital Expenditures (capex)

For 2013 our capex was about $31.4 million allocated as follows (in 000’s):

Carlisle - maintenance capex $14,602 
Carlisle - expansion/improvements  2,973 
Carlisle - land and minerals  346 
Ace - mine development  4,013 
Ace - surface equipment  5,858 
Other projects  3,685 
Items accrued for but not paid  (85)
Capex per the Cash Flow Statement $31,392 


19

Results of Operations

Quarterly coal sales and cost data (in 000’s):

2013 
  
1st
  
2nd
  
3rd
  
4th
  Full Year 
Tons sold  840   774   817   757   3,188 
Coal sales $33,995  $34,149  $34,985  $34,307  $137,436 
Average price/ton  40.47   44.12   42.82   45.32   43.11 
Wash plant recovery  74.0%   70.9%   68.0%   63.2%  69.0%
Operating costs $23,290  $22,262  $23,407  $23,934  $92,893 
Average cost/ton  27.73   28.76   28.65   31.62   29.14 
Margin  10,705   11,887   11,578   10,373   44,543 
Margin/ton  12.74   15.36   14.17   13.70   13.97 
Capex  8,604   6,174   8,780   7,834   31,392 

2012 
  
1st
  
2nd
  
3rd
  
4th
  Full Year 
Tons sold  701   743   810   752   3,006 
Coal sales $29,620  $32,487  $36,152  $33,111  $131,370 
Average price/ton  42.25   43.72   44.63   44.03   43.70 
Wash plant recovery  73.1%   71.2%   71.1%   71.7%   71.8% 
Operating costs $18,433  $18,816  $20,745  $21,745  $79,739 
Average cost/ton  26.29   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   15.12   17.17 
Capex  2,372   1,857   4,993   16,987   26,209 


 
Year
  Tons  Average Sales Price/ton  Average Cost/ton  
Margin/
ton
  
 
Margin
(in millions)
 
2012       3,006,000  $43.70  $26.53  $17.17  $51.6 
2013       3,188,000   43.11   29.14   13.97   44.5 
         2014*   3,504,000   42.72   28.50   14.22   49.8 
____________________________
*Sales are contracted for 2014. Average cost per ton is an estimate.

During much of 2013 we experienced difficult mining conditions and lower recoveries at Carlisle.  In the fourth quarter of 2013 we experienced our highest cost of production ever due to extremely low recovery.  Additionally, several production days were lost due to weather and operational issues at Carlisle.  We estimate 2014 costs will be lower than 2013 due to improving recovery.  We are making significant investments to our wash plant in an effort to improve recovery.  The wash plant recovery for January 2014 was 68.6%.  We are focused on reducing our costs to the projected $28.50/ton set forth in the table above. January 2014 costs per ton were less than the projected $28.50.

Capex in the fourth quarter of 2012 includes $9 million for the purchase of the Ace surface mine and another $4 million for land at Bulldog and Carlisle.
 
1020
 
Special Cash DividendsOther Analyses of Results of Operations

Savoy’s activity is discussed below.

The increase in equity income from Sunrise Energy was due to higher natgas prices.

The increase in DD&A was due to additions to plant and equipment.
 
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.Quarterly EPS
 
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.
2013
 
  
1st
 
2nd
 
3rd
 
4th
Basic  $.19                   $.29                $.17              $.16            
Diluted    .19                       .28                          .17                  .16             
2012
 
  
1st
 
2nd
 
3rd
 
4th
Basic  $.22                 $.23                $.22              $.18           
Diluted    .21                     .23                        .22               .17           

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 2011We do not recognize any revenue until customers have notified us that they accept 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.charges.  

We submitted our incurred costs for 2010 in September of 2011 for $4.2 million.  One of ourthe 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$3.7 million. We will not recognize any revenue until the customers have notified us that they accept the charges.  We$2.1 million in reimbursements 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 $2.52013 and $1.6 million were recorded 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,fourth quarter. Based on past experience we expect to participatecollect the 2012 costs 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 Mine2014 and the new Russellville unassigned reserve and 2012 political contributions of $225,000.

12
2013 costs in 2015.

Income Taxes

Our 2012During 2013 our effective tax rate was 31%25%.  For 2014, we are projecting an effective tax rate of 25% or slightly less.  Based on our projections, we are forecasting a total federal and state tax obligation in excess of existing prepayments of $4.6 million, resulting in additional outlays of cash for income taxes.  In addition, we expect such ratethe tax consequences between income tax and financial reporting purposes to beresult in a reduction to the 31-33% range for 2013. We estimate that 55% of such rate will be for taxes currently due.deferred tax liability with a corresponding deferred tax benefit. 

45% Ownership in Savoy
 
Savoy operates almost exclusively in Michigan.  They have an interest in the Trenton-Black River Play in Southernsouthern Michigan.  They hold 164,000144,000 gross acres (about 82,00072,000 net) in this area.  During 20122013 Savoy drilled 2730 gross wells in this play of which 1210 were dry, 17 were successful, and 15 were successful.three are still being evaluated. During 20132014 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 4030 and 50%60% and their net revenue interest averages between 3425 and 42%48%. Savoy’s net daily oil production currently averages 910 barrels of oil.about 1,100 barrels. Savoy has an interest in about 8396 gross wells (31(37 net).

21
Late last year Savoy engaged Energy Spectrum Advisors Inc. (ESA) to market its Trenton-Black River (TBR) operated oil properties located in southeast Michigan. ESA has offices in Dallas and Houston.  More information will be posted to the ESA website in early March 2014.

The reserve quantity and value information set forth in the tables below, do not agree to the Brock Engineering Report (see Note 6 to the financial statements) as such report only includes the TBR properties.  The other properties are not significant, but have been included in the tables below.  The TBR properties comprise about 95% of the PV10 amounts.
We are looking forward to the opportunity to potentially effect a monetization of our Savoy investment.  
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):
 
   
2013
   2012 
Revenue:
        
   Oil
 
$
32,057
  
$
25,830
 
   NGLs (natural gas liquids)
  
900
   
926
 
   Natgas
  
709
   
368
 
   Contract drilling
  
5,409
   
4,555
 
   Other
  
3,173
   
373
 
     Total revenue
  
42,248
   
32,052
 
Costs and expenses:
        
      LOE (lease operating expenses)
  
3,262
   
2,659
 
   Severance tax
  
2,476
   
2,015
 
   Contract drilling costs
  
3,520
   
3,161
 
   DD&A (depreciation, depletion & amortization)
  
5,802
   
6,387
 
   G&G (geological and geophysical costs)
  
5,084
   
3,208
 
   Dry hole costs
  
3,066
   
3,244
 
   Impairment of unproved properties
  
3,999
   
3,778
 
   Other exploration costs
  
451
   
340
 
   G&A (general & administrative)
  
1,662
   
1,287
 
   Stock option expense
      
1,448
 
      Total expenses
  
29,322
   
27,527
 
         
Net income
 
$
12,926
  
$
4,525
 
  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 – barrels
  
337,950
   
295,000
 
Average oil prices/barrel
 
$
95.00
  
$
88.00
 
Oil reserves in barrels
  
3,246,000
   
1,545,000
 
NGL reserves in barrels
  
218,000
   
64,000
 
Natgas reserves in Mcf
  
2,875,000
   
2,448,000
 
Oil prices/barrel used for PV 10
 
$
94.66
  
$
91.00
 
PV 10: proved reserves
 
$
200,707,000
  
$
78,000,000
 
PV 10: proved developed reserves
 
$
105,922,000
  
$
48,000,000
 

The data below is shown proportionate to our approximate 45% ownership in Savoy.
 
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
 
PV 10: proved reserves
 $90,820,000  $35,303,000 
PV 10: proved developed reserves
 $47,930,000  $21,725,000 

 
1322
 
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 Federalfederal tax return and our Indiana state tax return as “major” tax jurisdictions.  TheDuring 2012 the IRS recently completed an examination of our 2009 and 2010 federal tax returns and there were no significant adjustments.  During 2012 the stateState 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.

Yorktown Distributions

As previously disclosed, Yorktown Energy Partners and its affiliated partnerships (Yorktown) have made eight distributions to their numerous partners totaling 6 million (750,000 per distribution) shares since May 2011.  In the past these distributions were made soon after we filed our Form 10-Qs and Form 10-Ks.  Currently they own 9.7 million shares of our stock representing about 34% 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.

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.

23

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
 
 
Report of Independent Registered Public Accounting Firm1525 
   
Consolidated Balance Sheet1626 
   
Consolidated Statement of Comprehensive Income1727 
   
Consolidated Statement of Cash Flows1828 
   
Consolidated Statement of Stockholders' Equity1929 
   
Notes to Consolidated Financial Statements2030 


Smaller reporting companies are not required to provide supplementary data.





 
1424
 







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, 20112012 and 2012,2013, 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, 2012.2013.  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, 20112012 and 2012,2013, and the results of their operations and their cash flows for each of the years in the two year period ended December 31, 2012,2013, in conformity with accounting principles generally accepted in the United States of America.



/s/ EKS&H LLLP

March 6, 2013February 28, 2014
Denver, Colorado


 
1525
 


I
Consolidated Balance Sheet
As of December 31,
(in thousands, except per share data)
ASSETS
 
2012
 
2011
  
2013
 
2012
 
Current assets:
          
Cash and cash equivalents
 
$
21,888
 
$
37,542
  
$
16,228
 
$
21,888
 
Accounts receivable
 
8,127
 
6,689
  
10,577
 
8,127
 
Prepaid income taxes
 
4,661
   
Coal inventory
 
2,342
 
1,863
  
4,778
 
2,342
 
Parts and supply inventory
 
2,264
 
2,202
  
2,826
 
2,264
 
Other
  
242
  
580
   
291
  
242
 
Total current assets
  
34,863
  
48,876
   
39,361
  
34,863
 
          
Coal properties, at cost:
          
Land and mineral rights
 
22,705
 
16,465
  
26,476
 
22,705
 
Buildings and equipment
 
131,566
 
121,242
  
148,077
 
131,566
 
Mine development
  
71,046
  
66,614
   
85,333
  
71,046
 
 
225,317
 
204,321
  
259,886
 
225,317
 
Less - accumulated DD&A
  
(58,479
)
  
(42,493
)
  
(77,545
)
  
(58,479
)
 
166,838
 
161,828
  
182,341
 
166,838
 
Investment in Savoy
 
12,230
 
12,133
  
16,733
 
12,230
 
Investment in Sunrise Energy
 
3,969
 
3,297
  
4,573
 
3,969
 
Other assets (Note 9)
  
11,307
  
6,294
   
17,405
  
11,307
 
 
$
229,207
 
$
232,428
  
$
260,413
 
$
229,207
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
          
Current liabilities:
          
Current portion of bank debt
 
$
  
$
17,500
 
Accounts payable and accrued liabilities
 
9,386
 
10,411
  
 $
10,357
 
 $
9,386
 
Income taxes
 
1,660
 
5,125
      
1,660
 
Other
     
60
 
Total current liabilities
  
11,046
  
33,096
   
10,357
  
11,046
 
          
Long-term liabilities:
          
Bank debt
 
11,400
    
16,000
 
11,400
 
Deferred income taxes
 
35,884
 
31,100
  
43,304
 
35,863
 
Asset retirement obligations
 
2,573
 
2,276
  
5,290
 
2,573
 
Other
  
6,295
  
4,963
   
2,128
  
6,316
 
Total long-term liabilities
  
56,152
  
38,339
   
66,722
  
56,152
 
Total liabilities
  
67,198
  
71,435
   
77,079
  
67,198
 
Commitments and contingencies
          
Stockholders’ equity:
          
Preferred stock, $.10 par value, 10,000 shares authorized; none issued
          
Common stock, $.01 par value, 100,000 shares authorized;
28,529 and 28,309 outstanding, respectively
 
285
 
283
 
Common stock, $.01 par value, 100,000 shares authorized; 28,751 and 28,529 outstanding, respectively
 
287
 
285
 
Additional paid-in capital
 
86,576
 
85,984
  
87,872
 
86,576
 
Retained earnings
 
75,118
 
74,685
  
94,796
 
75,118
 
Accumulated other comprehensive income
  
30
  
41
   
379
  
30
 
Total stockholders’ equity
  
162,009
  
160,993
   
183,334
  
162,009
 
 
$
229,207
 
$
232,428
  
$
260,413
 
$
229,207
 



See accompanying notes.




 
1626
 





Consolidated Statement of Comprehensive Income
For the years ended December 31,
(in thousands, except per share data)
 
 
 2012 2011 
      2013 2012 
Revenue:
          
Coal sales
 
$
131,370
 
$
137,998
  
$
137,436
 
$
131,370
 
Equity income - Savoy
 
2,039
 
5,476
 
Equity income – Savoy
 
5,827
 
2,039
 
Equity income - Sunrise Energy
 
167
 
922 
  
629
 
167
 
Gain on sale of unproved oil and gas properties
 
303
 
10,653
 
Liability extinguishment (Note 12)
 
4,300
   
Gain on sale of land
 
2,748
      
2,748
 
Other income (Note 9)
  
4,696
  
2,305
   
5,678
  
4,999
 
  
141,323
  
157,354
   
153,870
  
141,323
 
Costs and expenses:
          
Operating costs and expenses
 
79,739
 
77,094
  
92,893
 
79,739
 
DD&A
 
16,028
 
14,096
  
18,585
 
16,028
 
Coal exploration costs
 
2,453
 
1,132
  
2,360
 
2,453
 
SG&A
 
7,532
 
7,004
  
7,669
 
7,532
 
Interest
  
1,096
  
1,288
   
1,547
  
1,096
 
  
106,848
  
100,614
   
123,054
  
106,848
 
          
Income before income taxes
  
34,475
  
56,740
   
30,816
  
34,475
 
          
Less income taxes:
          
Current
 
5,905
 
7,266
  
221
 
5,905
 
Deferred
  
4,763
  
13,665
   
7,441
  
4,763
 
  
10,668
  
20,931
   
7,662
  
10,668
 
          
Net income*
 
$
23,807
 
$
35,809
  
$
23,154
 
$
23,807
 
          
Net income per share:
          
Basic
 
$
.84
 
$
1.27
  
$
.81
 
$
.84
 
Diluted
 
$
.83
 
$
1.25
  
$
.80
 
$
.83
 
          
Weighted average shares outstanding:
          
Basic
 
28,331
 
28,135
  
28,595
 
28,331
 
Diluted
 
28,843
 
28,694
  
28,906
 
28,843
 
_______________________
--------------------------------------------------------------------------------------
 *There*There is no material difference between net income and comprehensive income.
 
 
See accompanying notes.







See accompanying notes.
 
1727
 





Consolidated Statement of Cash Flows
For the years ended December 31,
(in thousands)
  
  2012  2011 
Operating activities:
      
Net income
 
$
23,807
  
$
35,809
 
Gain on sale
  
(3,051
)
  
(10,653
)
Deferred income taxes
  
4,763
   
13,665
 
Equity income – Savoy and Sunrise Energy
  
(2,206
)
  
(6,398
)
Cash distributions from Savoy
  
1,943
   
1,060
 
DD&A
  
16,028
   
14,096
 
Stock-based compensation
  
2,655
   
2,331
 
Taxes paid on vesting of RSUs
  
(739
)
  
(1,661
)
Change in current assets and liabilities:
        
Accounts receivable
  
(1,058
)
  
221
 
Coal inventory
  
(479
)
  
236
 
Income taxes
  
(3,465
)
  
8,978
 
Accounts payable and accrued liabilities
  
1,060
   
1,751
 
Other
  
(2,216
)
  
1,285
 
Cash provided by operating activities
  
37,042
   
60,720
 
Investing activities:
        
Proceeds from sale of properties
  
7,630
   
13,195
 
Capital expenditures for coal properties
  
(26,209
)
  
(32,995
)
Investment in Sunrise Energy
  
(506
)
    
Marketable securities
  
(1,221
)
  
(2,257
)
Other
  
(48
)
  
865
 
Cash used in investing activities
  
(20,354
)
  
(21,192
)
Financing activities:
        
Payments of bank debt
  
(7,500
)
  
(10,000
)
Bank borrowings
  
1,400
     
Deferred financing costs
  
(1,544
)
    
Dividends
  
(23,374
)
  
(3,505
)
Stock option buy-out
  
(1,461
)
    
Tax benefit from stock-based compensation
  
137
   
1,242
 
Cash used in financing activities
  
(32,342
)
  
(12,263
)
Increase (decrease) in cash and cash equivalents
  
(15,654
)
  
27,265
 
Cash and cash equivalents, beginning of year
  
37,542
   
10,277
 
Cash and cash equivalents, end of year
 
$
21,888
  
$
37,542
 
         
Cash paid for interest
 
$
622
  
$
1,508
 
Cash paid for income taxes
 
$
9,250
  
$
100
 
Changes in accounts payable for coal properties
 
$
(567
)
 
$
(358
)

  2013  2012 
Operating activities:
      
Net income
 
$
23,154
  
$
23,807
 
Gain on sale
      
(2,748
)
Liability extinguishment
  
(4,300
)
    
Deferred income taxes
  
7,441
   
4,763
 
Equity income – Savoy and Sunrise Energy
  
(6,456
)
  
(2,206
)
Cash distributions from Savoy and Sunrise Energy
  
1,325
   
1,943
 
DD&A
  
18,585
   
16,028
 
Stock-based compensation
  
2,155
   
2,655
 
Taxes paid on vesting of RSUs
  
(780
)
  
(739
)
Change in current assets and liabilities:
        
Accounts receivable
  
(2,394
)
  
(1,058
) 
Coal inventory
  
(2,436
)
  
(479
) 
Income taxes
  
(6,327
)
  
(3,465
) 
Accounts payable and accrued liabilities
  
1,130
   
1,060
 
Other
  
(3,916
)
  
(2,519
) 
Cash provided by operating activities
  
27,181
   
37,042
 
Investing activities:
        
Proceeds from sale of properties
      
7,630
 
Capital expenditures for coal properties
  
(31,392
)
  
(26,209
)
Ohio River terminal
  
(2,836
)
    
Investment in Sunrise Energy
      
(506
) 
Marketable securities
      
(1,221
)
Other
  
263
   
(48
) 
Cash used in investing activities
  
(33,965
)
  
(20,354
)
Financing activities:
        
Payments of bank debt
      
(7,500
)
Bank borrowings
  
4,600
   
1,400
 
Deferred financing costs
      
(1,544
)
Dividends
  
(3,476
)
  
(23,374
)
Stock option buy-out
      
(1,461
) 
Other
      
137
 
Cash provided by (used in) financing activities
  
1,124
   
(32,342
)
Decrease in cash and cash equivalents
  
(5,660
)
  
(15,654
) 
Cash and cash equivalents, beginning of year
  
21,888
   
37,542
 
Cash and cash equivalents, end of year
 
$
16,228
  
$
21,888
 
         
Cash paid for interest
 
$
1,028
  
$
622
 
Cash paid for income taxes
  
6,045
   
9,250
 
Increase in ARO
  
2,535
   
159
 





See accompanying notes.


 
1828
 



Consolidated Statement of Stockholders’ Equity
(in thousands)
 
 
  Shares  Common Stock  Additional Paid-in Capital  Retained Earnings  AOCI*  Total 
Balance January 1, 2011
  
27,924
  
$
279
  
$
84,073
  
$
42,381
     
$
126,733
 
                        
Stock-based compensation
  
11
       
2,331
          
2,331
 
Exercise of employee stock options for shares
  
181
   
1
   
(1
)
           
Taxes paid for shares issued to employees
  
(41
)
      
(469
)
         
(469
)
Stock issued on vesting of RSUs
  
345
   
3
              
3
 
Taxes paid on vesting of RSUs
  
(111
)
      
(1,192
)
         
(1,192
)
Tax benefit from stock-based compensation
          
1,242
          
1,242
 
Dividends
              
(3,505
)
     
(3,505
)
Net income
              
35,809
      
35,809
 
Other
                 
$
41
   
41
 
Balance December 31, 2011
  
28,309
   
283
   
85,984
   
74,685
   
41
   
160,993
 
                         
Stock-based compensation
  
20
       
2,655
           
2,655
 
Stock issued on vesting of RSUs
  
290
   
2
               
2
 
Taxes paid on vesting of RSUs
  
(90
)
      
(739
)
          
(739
)
Stock option buy-out for cash
          
(1,461
)
          
(1,461
)
Tax benefit from stock-based compensation
          
137
           
137
 
Dividends
              
( 23,374
)
      
(23,374
)
Net income
              
23,807
       
23,807
 
Other
                  
(11
)
  
(11
)
Balance December 31, 2012
  
28,529
  
$
285
  
$
86,576
  
$
75,118
  
$
30
  
$
162,009
 
  
Shares
  
Common Stock
  
Additional Paid-in Capital
  
Retained Earnings
  
Accumulated Other Comprehensive Income
  
Total
 
Balance January 1, 2012
  28,309  $283  $85,984  $74,685  $41  $160,993 
                         
   Stock-based compensation
  20       2,655           2,655 
Stock issued on vesting of RSUs
  290   2               2 
Taxes paid on vesting of  RSUs
  (90)      (739)          (739)
Stock option buy-out for cash
          (1,461)          (1,461)
Dividends
              (23,374)      (23,374)
Net income
              23,807       23,807 
Other
          137       (11)  126 
Balance December 31, 2012
  28,529   285   86,576   75,118   30   162,009 
                         
   Stock-based compensation
  13       2,155           2,155 
Stock issued on vesting of RSUs
  316   2               2 
Taxes paid on vesting of    RSUs
  (107)      (780)          (780)
Dividends
              (3,476)      (3,476)
Net income
              23,154       23,154 
   Other
          (79)       349   270 
Balance December 31, 2013
  28,751  $287  $87,872  $94,796  $379  $183,334 




 




See accompanying notes.

*Accumulated Other Comprehensive Income

 
1929
 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
(1)   Summary of Significant Accounting Policies
 
Basis of Presentation and Consolidation
 
The consolidated financial statements include the accounts of Hallador Energy Company (the “Company”) and its wholly-owned subsidiary Sunrise Coal, LLC (Sunrise).  All significant intercompany accounts and transactions have been eliminated.  We are engaged in the production of steam coal from mines located in western Indiana.  We own a 45% equity interest in Savoy Energy L.P., a private oil and gas company which has operations in Michigan and a 50% interest in Sunrise Energy LLC, a private entity engaged primarily in natgas operations in the same vicinity as our coalthe Carlisle mine.
 
Reclassification
 
To maintain consistency and comparability, certain amounts in the 20112012 financial statements have been reclassified to conform to current year presentation.
 
Inventories
 
Coal and supplies inventories are valued at the lower of average cost or market. Coal inventory costs include labor, supplies, equipment costs and overhead.
 
Advance Royalties
 
Coal leases that require minimum annual or advance payments and are recoverable from future production are generally deferred and charged to expense as the coal is subsequently produced.
 
Coal Properties
 
Coal properties are recorded at cost. Interest costs applicable to major asset additions are capitalized during the construction period. Expenditures that extend the useful lives or increase the productivity of the assets are capitalized. The cost of maintenance and repairs that do not extend the useful lives or increase the productivity of the assets are expensed as incurred.  Other than land and underground mining equipment, coal properties are depreciated using the units-of-production method over the estimated recoverable reserves. Surface and underground mining equipment is depreciated using estimated useful lives ranging from five to twenty years.
 
If facts and circumstances suggest that a long-lived asset may be impaired, the carrying value is reviewed for recoverability. If this review indicates that the carrying value of the asset will not be recoverable through estimated undiscounted future net cash flows related to the asset over its remaining life, then an impairment loss is recognized by reducing the carrying value of the asset to its estimated fair value.
 
Mine Development
 
Costs of developing new coal mines, including asset retirement obligation assets, or significantly expanding the capacity of existing mines, are capitalized and amortized using the units-of-production method over estimated recoverable (proved and probable) reserves.
 
Asset Retirement Obligations (ARO) - Reclamation
 
At the time they are incurred, legal obligations associated with the retirement of long-lived assets are reflected at their estimated fair value, with a corresponding charge to mine development. Obligations are typically incurred when we commence development of underground and surface mines, and include reclamation of support facilities, refuse areas and slurry ponds.

30
Obligations are reflected at the present value of their future cash flows.  We reflect accretion of the obligations
for the period from the date they are incurred through the date they are extinguished. The asset retirement obligation assets are amortized using the units-of-production method over estimated recoverable (proved and probable) reserves.  We are using a 6%5.5% discount rate.
 
20
Federal and state laws require that mines be reclaimed in accordance with specific standards and approved reclamation plans, as outlined in mining permits.  Activities include reclamation of pit and support acreage at surface mines, sealing portals at underground mines, and reclamation of refuse areas and slurry ponds.
 
We assess our ARO at least annually and reflect revisions for permit changes, changes in our estimated reclamation costs and changes in the estimated timing of such costs.
 
The table below (in thousands) reflects the changes to our ARO:
 2012 2011  2013 2012 
Balance beginning of year
 
$
2,276
 
$
1,150
  
$
2,573
 
$
2,276
 
Accretion
 
138
 
76
  
182
 
138
 
Additions
  
159
  
1,050
 
Additions – primarily Ace for 2013
  
2,535
  
159
 
Balance end of year
 
$
2,573
 
$
2,276
  
$
5,290
 
$
2,573
 
 
Statement of Cash Flows
 
Cash equivalents include investments with maturities when purchased of three months or less.
 
Income Taxes
 
Income taxes are provided based on the liability method of accounting.  The provision for income taxes is based on pretax financial income. Deferred tax assets and liabilities are recognized for the future expected tax consequences of temporary differences between income tax and financial reporting and principally relate to differences in the tax basis of assets and liabilities and their reported amounts, using enacted tax rates in effect for the year in which differences are expected to reverse.
 
Earnings per Share
 
Basic earnings per share are computed on the basis of the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share are computed on the basis of the weighted average number of shares of common stock plus the effect of dilutive potential common shares outstanding during the period using the treasury stock method. Dilutive potential common shares include restricted stock units. 
 
Use of Estimates in the Preparation of Financial Statements
 
The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period.  Actual amounts could differ from those estimates.  The most significant estimates included in the preparation of the financial statements are related to deferred income tax assets and liabilities and coal reserves.
 
Revenue Recognition
 
We recognize revenue from coal sales at the time risk of loss passes to the customer at contracted amounts and amounts are deemed collectible.
 
31
Long-term Contracts
 
We evaluate each of our contracts to determine whether they meet the definition of a derivative and they do not.  As of December 31, 2012,2013, we are committed to supply to threeour customers 4.95.8 million tons of coal during the next twothree years. During 20122013 four of our customers accounted for 94% of our coal sales: one for 39%, the second for 29%, the third for 14% and 2011,the fourth for 12%. During 2012 three of our customers accounted for 90% or more93% of our coal sales: for 2012, one customer accounted for 46%, the second for 31%, and the third for 16%; for 2011, one customer accounted for 43%, the second for 29%, and the third for 17%.

We are paid every two to four weeks and do not expect any credit losses.

Stock-based Compensation

Stock-based compensation is measured at the grant date based on the fair value of the award and is recognized as expense over the applicable vesting period of the stock award (generally three to four years) using the straight-line method.
 
21
New Accounting Pronouncements
 
None of the recent FASB pronouncements will have any material effect on us.
 
Subsequent Events
 
We have evaluated all subsequent events through the date the financial statements were issued. No material recognized or non-recognizable subsequent events were identified.
 
(2)   Bill and Hold
 
EarlierEarly in 2012 two of our customers advised us that their coal stockpiles were increasing and asked us to consider storing their coal on our property. In April 2012 we entered into a storage agreement with one customer to store 250,000 tons for a minimum of one year and up to a maximum of two years. In June 2012 we entered into a similar storage agreement with the second customer. During the 2013 second quarter we increased the storage agreement by 50,000 tons for one of the customers. We continue to sell the coal as contracted to these customers.  The risks and rewards of ownership pass from us to them as coal is placed into segregated storage. We are paid a nominal storage fee in addition to our contracted price at the time the coal is placed in storage. AsDuring the first half of December 31, 2012, we have stored 250,0002013, 145,000 tons were placed in storage for the first customer and 155,000 tonsnil for the second.second customer. We have recognized about $20$7.3 million in revenue from these “bill and hold” arrangements.arrangements for 2013. No tons were placed in storage during the last half of 2013. As of December 31, 2013, we have in storage 300,000 tons for the first customer and 250,000 tons for the second. There were no changechanges in payment terms with our customers and, as of JanuaryDecember 31, 2013, all receivables outstanding at December 31, 2012 havefrom these two customers had been collected.

(3)   Income Taxes (in thousands)
 
Our income tax is different than the expected amount computed using the applicable federal and state statutory income tax rates.  The reasons for and effects of such differences for the years ended December 31 are below: 
 
 2012 2011  2013 2012 
Expected amount
 
$
12,064
 
$
19,859
  
$
10,784
 
$
12,064
 
State income taxes, net of federal benefit
 
1,723
 
2,950
  
1,540
 
1,723
 
Percentage depletion
 
(4,373
)
 
(1,816
)
Other
  
(3,119
)
  
(1,878
)
  
(289
)
  
(1,303
)
 
$
10,668
 
$
20,931
  
$
7,662
 
$
10,668
 


 
32
 

The deferred tax assets and liabilities resulting from temporary differences between book and tax basis are comprised of the following at December 31:
 
 2012 2011  2013 2012 
Long-term deferred tax assets:
          
AMT credit carryforwards
 
$
-
 
$
1,137
 
Stock-based compensation
 
582
 
596
  
 $
372
 
 $
582
 
Investment in Savoy
 
1,582
 
960
  
1,885
 
1,582
 
Oil and gas properties
  
1,778
  
1,540
   
913
  
1,778
 
Net long-term deferred tax assets
 
3,942
 
4,233
  
3,170
 
3,942
 
Long-term deferred tax liabilities:
          
Coal properties
  
(39,826
)
  
(35,333
)
  
(46,474
)
  
(39,805
)
Net deferred tax liability
 
$
35,884
 
$
31,100
  
$
43,304
 
$
35,863
 
 
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.  TheDuring 2012 the IRS recently completed an examination of our 2009 and 2010 federal tax returns and there were no significant adjustments.  During 2012 the stateState 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.

22
(4)   Stock Compensation Plans
 
Restricted Stock Units
 
At December 31, 20122013 we had 481,500164,000 Restricted Stock Units (RSUs) outstanding and 870,000840,000 available for future issuance.  The outstanding RSUs have a value of $3.5$9 million based on our current stock price of $7.34.  During 2011,$8.21.  On February 1, 2014 we granted 30,000920,000 RSUs with cliff vestingto key employees of which 720,000 vest equally over three years; ourfour years and 200,000 over two years. Our stock closed at $11price on grant date.date was $7.66.  In April 2012, we granted 143,000 RSUs with cliff vesting over three years; our stock closed at $9 on grant date. We expect 315,000310,000 RSUs to vestvest/lapse during 20132014 under our current vesting schedule.
 
During 20122013 and 2011,2012, there were 297,500315,500 and 345,000297,500 RSUs that vested, respectively. On the vesting dates the shares had a value of $2.2$2.3 million for 20122013 and $3.7$2.4 million for 2011.2012. Under our RSU plan participants are allowed to relinquish shares to pay for their required minimum statutory income taxes.
 
Stock-based compensation expense for 2013 was $2.2 million and for 2012 was $2.7 million and for 2011 was $2.3 million. For 20132014, based on existing RSUs outstanding, stock-based compensation expense will be $2.2$2.7 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 in late 2009 with 250,000 shares. As mentioned above under Stock Options, during January 2011, about 140,000 shares were issued.  Currently, we have about 86,000 shares left in such plan.
 
33
(5)   Bank Debt
 
During October 2012, Sunrise Coal, our wholly-owned subsidiary, entered into a new credit agreement (the “Credit Agreement”) with PNC Bank, as administrative agent, and the lenders named therein. The Credit Agreement replacesreplaced the previous credit agreement we had with PNC. Closing costs on this new facility were
about $1.5 million which were deferred and are being amortized over five years.  Outstanding debt at December 31, 20122013 was $11.4$16 million.
 
The Credit Agreement provides for a $165 million senior secured revolving credit facility. The facility matures in five years. The facility is collateralized by substantially all of Sunrise’s assets and we are the guarantor. We will draw on the facility as needed for development of our new projects in Illinois and Indiana.
 
All borrowings under the Credit Agreement bear interest, at LIBOR plus 2% if the leverage ratio is less than 1.5X (which it currently is), LIBOR plus 2.5% if the leverage ratio is over 1.5 but less than 2X and at LIBOR plus 3% if the leverage ratio is over 2X. LIBOR was 17 BPS at December 31, 2013. The maximum leverage ratio is 2.75X.  The leverage ratio is equal to funded debt/EBITDA.TheEBITDA. The annual commitment fee is 50 BPS but falls to 37.5 BPS if we borrow more than 33% of the facility.  The maximum that we can currently borrow is $125 million.$126 million due to our current covenants. The Credit Agreement also imposes certain other customary restrictions and covenants as well as certain milestones we must meet in order to draw down the full amount.
 
23
(6)   Equity Investment in Savoy
 
We own a 45% interest in Savoy Energy L.P. (Savoy), a private company engaged in the oil and gas business primarily in the Statestate of Michigan.  Savoy uses the successful efforts method of accounting.  We account for our interest in Savoy using the equity method of accounting.

Below (in thousands) to the 100% is a condensed balance sheet at December 31, for both years and a condensed statement of operations for both years.
 
Condensed Balance Sheet

 2012 2011  2013 2012 
Current assets
 
$
16,207
 
$
16,200
  
$
29,182
 
$
16,207
 
Oil and gas properties, net
 
21,065
 
17,973
  
25,408
 
21,065
 
Other
  
263
  
2,152
   
260
  
263
 
 
$
37,535
 
$
36,325
  
$
54,850
 
$
37,535
 
          
Total liabilities
 
$
9,116
 
$
9,469
  
$
16,447
 
$
9,116
 
Partners' capital
  
28,419
  
26,856
   
38,403
  
28,419
 
 
$
37,535
 
$
36,325
  
$
54,850
 
$
37,535
 
 
Condensed Statement of Operations

 2012 2011  2013 2012 
Revenue
 
$
32,052
 
$
31,997
  
$
42,248
 
$
32,052
 
Expenses
  
(27,527
)
  
(19,897
)
  
(29,322
)
  
(27,527
)
Net income
 
$
4,525
 
$
12,100
  
$
12,926
 
$
4,525
 

Late last year Savoy engaged Energy Spectrum Advisors Inc. (ESA) to market its Trenton-Black River (TBR) oil properties located in southeast Michigan. ESA has offices in Dallas and Houston.  More information will be posted to the ESA website in early March 2014.

34
The reserve quantity and value information set forth in the tables below, do not agree to the Brock Engineering Report as such report only includes the TBR properties.  The other properties are not significant, but have been included in the tables below.  The TBR properties comprise about 95% of the PV10 amounts.
We are looking forward to the opportunity to potentially effect a monetization of our Savoy investment.  
Unaudited Oil and Gas Reserve Quantity and Value Information (in thousands)
The data below is shown proportionate to our approximate 45% ownership in Savoy.

Costs incurred are as follows:

  2013 
Unproved property acquisition $1,287 
Development  858 
Exploration  7,061 
Total $9,206 

  
Oil
(Bbls)
  
NGLs
(Bbls)
  
Natgas
(Mcf)
 
          
January 1, 2013  700   29   1,108 
Extensions and discoveries  898   58   442 
Production  (153)  (11)  (96)
Revisions to previous estimates  24   23   (153)
December 31, 2013  1,469   99   1,301 
             
Proved developed reserves  746   60   450 
Proved undeveloped reserves (PUDs)  723   39   851 

  
Proved
Developed
  PUDs  
Total
Proved
 
Future cash flows:         
Oil $70,582  $70,662  $141,244 
NGLs  2,551   1,669   4,220 
Natgas  1,365   976   2,341 
Total cash flows  74,498   73,307   147,805 
Future production costs  (12,213)  (12,233)  (24,446)
Future development costs      (3,073)  (3,073)
Future income tax (none since Savoy is a pass-through entity for income tax purposes)            
Future net cash flows  62,285   58,001   120,286 
10% annual discount for estimated timing of cash flows  (14,355)  (15,111)  (29,466)
Standardized measure of discounted future net cash flows $47,930  $42,890  $90,820 
             


35


2013
Beginning of year$ 35,300
Sales, net of production costs(12,640)
Net changes in prices and production costs1,600
Extensions and discoveries57,200
Revisions of previous quantity estimates2,100
Change in production timing and other3,700
Accretion of discount3,560
End of year$ 90,820
Average wellhead prices:
Oil (per Bbl)$94.66
NGLs (per Bbl)42.45
Natgas (per Mcf)3.04


The 2013 reserve estimates shown above have been independently evaluated by Brock Engineering, LLC, which customarily prepares petroleum property analysis for industry and financial organizations and government agencies. Brock Engineering was founded in 1997 and performs consulting petroleum engineering services. Within Brock Engineering, the technical personnel responsible for preparing the estimates set forth in the Brock Engineering reserves report incorporated herein are Timothy J. Brock and Douglas J. Elenbaas. Mr. Brock has been practicing consulting petroleum engineering at Brock Engineering since 1997. Mr. Brock is a Licensed Professional Engineer in the State of Michigan (No. 39603) and has over 33 years of experience in the estimation and evaluation of reserves. He graduated from Michigan Technological University in 1980 with a Bachelor of Science Degree in Geological Engineering. He meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering evaluations as well as applying SEC and other industry reserves definitions and guidelines. Mr. Elenbaas has been practicing consulting petroleum engineering at Brock Engineering since 2012. Mr. Elenbaas is a Licensed Professional Engineer in the State of Michigan (No. 32030) and has over 30 years of experience in the estimation and evaluation of reserves. He graduated from the University of Michigan in 1977 with a Bachelor of Science Degree in Chemical Engineering. He meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering evaluations as well as applying SEC and other industry reserves definitions and guidelines.

The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.
36
(7)   Equity   Investment in Sunrise Energy

In late December 2010 we invested $2.4 million forWe own a 50% interest in Sunrise Energy, LLC which then purchased existingowns gas reserves and gathering equipment from an unrelated third party with plans to develop and operate such reserves.  An additional $506,000 was invested in January 2012. Sunrise Energy also plans to develop and explore for coal-bed methane gas reserves on or near our underground coal reserves. Development is pending an increase in natgas prices. They use the successful efforts method of accounting. We account for our interest using the equity method of accounting.

Below (in thousands) to the 100% is a condensed balance sheet at December 31, for both years and a condensed statement of operations for both years.  Sunrise Energy’s proved oil and gas reserves are not material. 

Condensed Balance Sheet

     
 2012 2011  2013 2012 
Current assets
 
$
1,754
 
$
1,916
  
$
3,109
 
$
1,754
 
Oil and gas properties, net
  
6,934
  
6,236
   
6,781
  
6,934
 
 
$
8,688
 
$
8,152
  
$
9,890
 
$
8,688
 
          
Total liabilities
 
$
762
 
$
1,558
  
$
756
 
$
762
 
Members' capital
  
7,926
  
6,594
   
9,134
  
7,926
 
 
$
8,688
 
$
8,152
  
$
9,890
 
$
8,688
 
 

Condensed Statement of Operations

 2012 2011  2013 2012 
Revenue
 
$
2,450
 
$
3,951
  
$
3,399
 
$
2,450
 
Expenses
  
(2,117
)
  
(2,107
)
  
(2,141
)
  
(2,117
)
Net income
 
$
333
 
$
1,844
  
$
1,258
 
$
333
 
 
24
(8)   Employee Benefits
 
We have no defined benefit pension plans or any post-retirement benefit plans.  We offer our employees a 401(k) Plan, where we match 100% of the first 4% that an employee contributes, a bonus plan based on meeting certain production levels and a discretionary Deferred Bonus Plan for certain key employees.  We also offer health benefits to all employees and their families.  We have 1,0501,162 participants in our employee health plan. The plan does not cover dental, vision, short-term or long-term disability. These coverages are available on a voluntary basis.  We bear some of the risk of our employee health plans. Our health claims are capped at $110,000 per person with a maximum annual exposure of $3.6$4 million not including premiums. Our 2013 expense for the 401(k) matching was $700,000 and our expense for health benefits was $4.1 million. Our 2012 expense for the 401(k) matching was $0.617 million$656,000 and our expense for health benefits was $3.6 million. Our 2011 expense for the 401(k) matching was $0.486 million and our expense for health benefits was $3.2$3.65 million.   The 20122013 expense for the Deferred Bonus Plan was $367,000$467,000 and the 20112012 expense was $254,000.$367,000. The expense for the production bonus plan was $582,000 for 2013 and $684,000 for 2012 and $910,000 for 2011.2012.
 
Our mine employees are also covered by workers’ compensation and such costs for 20122013 and 20112012 were about $0.875$1.3 million and $1.3 million,$875,000, respectively. Workers’ compensation is a no-fault system by which individuals who sustain work related injuries or occupational diseases are compensated. Benefits and coverage are mandated by each state which includes disability ratings, medical claims, rehabilitation services, and death and survivor benefits.  Our operations are protected from these perils through insurance policies.  Our maximum annual exposure is limited to $1 million per employeeoccurrence with a $4 million aggregate deductible.  Based on discussions and representations from our insurance carrier we believe that our reserve for our workers’ compensation benefits is adequate.  We have a safety conscious work forceworkforce and our worker’s compensation injuries have been minimal.  Our Carlisle mine has been in operation for six years.

 
37
(9) Other Long-term Assets and Other Income

  2013  2012 
Long-term assets:
      
Advance coal royalties
 
$
4,693
  
$
3,324
 
Deferred financing costs, net
  
1,195
   
1,494
 
Marketable equity securities available for sale, at fair value (restricted)*
  
3,889
   
3,548
 
Ohio River Terminal (see Note 11)
  
2,836
     
Miscellaneous
  
4,792
   
2,941
 
 ___________________
 
$
17,405
  
$
11,307
 
*Held by Sunrise Indemnity, Inc., our wholly-owned captive insurance company.
 
        
Other income:
        
MSHA reimbursements**
 
$
3,672
  
$
4,236
 
Coal storage fees
  
1,238
   
304
 
Miscellaneous
  
768
   
459
 
  
$
5,678
  
$
4,999
 
 
  2012  2011 
Long-term assets:
      
Advance coal royalties
 
$
3,324
  
$
3,205
 
Deferred financing costs, net
  
1,494
   
295
 
Marketable equity securities available for sale at fair value (restricted)*
  
3,548
   
2,326
 
Miscellaneous
  
2,941
   
468
 
  
$
11,307
  
$
6,294
 

*Held by Sunrise Indemnity, Inc., our wholly-owned captive insurance company.
        
Other income:
        
MSHA reimbursements**
 
$
4,236
  
$
1,900
 
Miscellaneous
  
460
   
405
 
  
$
4,696
  
$
2,305
 
_____________________
**See “MSHA Reimbursements” in the MD&A section for a discussion of these amounts.
 
(10)    Self Insurance
 
In late August 2010 we decided to terminate the property insurance on our underground mining equipment. Such equipment is allocated among five mining units spread out over 1114 miles.  The historical cost of such equipment is about $100$107 million.
 
(11)  GainOhio River Terminal

On May 31, 2013 we purchased for $2.8 million a multi-commodity truck/barge terminal. Over 17 acres of secured area is available. The terminal is at mile point 743.8 on Sale
See “North Dakota Lease Play” in our MD&A section for a discussionthe Indiana bank of the $10.7 million gain on sale recognizedOhio River near the William Natcher Bridge between Rockport and Grandview, Indiana.  Currently the dock will handle third party commodities.  In the long term, we plan to ship coal through the dock.  The terminal is in 2011.close proximity to the NS railroad, the CSX railroad and American Electric Power's Rockport generating power plant. We do not expect revenue from this asset until 2015.

(12)  Liability Extinguishment

During the 2013 second quarter we concluded that an approximate $4.3 million liability we recorded during 2006 upon the purchase of Sunrise relating to a terminated coal contract was no longer required. The amount had no affect on cash flows.


38
ITEM 9:  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
 
Not applicable.


ITEM 9A.   CONTROLS AND PROCEDURES.
 
Disclosure Controls

We maintain a system of disclosure controls and procedures that are designed for the purposes of ensuring that information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to our CEO and CFO as appropriate to allow timely decisions regarding required disclosure.
 
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our CEO and CFO of the effectiveness of the design and operation of our disclosure controls and procedures. Based upon that evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective for the purposes discussed above.

Internal Control Over Financial Reporting (ICFR)

We are responsible for establishing and maintaining adequate ICFR.  We assessed the effectiveness of our ICFR based on criteria for effective ICFR described in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Based on our assessment, we concluded that we maintained effective ICFR as of December 31, 2012.2013.

There has been no change in our internal control over financial reporting during the quarter ended December 31, 20122013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

This annual report does not include an attestation report from EKSH our auditors, regarding ICFR.  Our report was not subject to attestation by EKSH pursuant to existing rules of the SEC that permits us to provide only our report in this annual report.

ITEM 9B.  OTHER INFORMATION        None.

PART III

The information required for Items 10-14 are hereby incorporated by reference to that certain information in our Information Statement to be filed with the SEC during March 2013.2014.

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.


ITEM 11.   EXECUTIVE COMPENSATION


ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.


ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.


ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES.
.

 
2639
 



PART IV

ITEM 15.   EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
 
See Item 8 for an index of our financial statements.

Because we are a smaller reporting company we are not required to provide financial statement schedules.

Our exhibit index is as follows:

3.1
Second Restated Articles of Incorporation of Hallador Energy Company effective December 24, 2009. (1)
3.2
By-laws of Hallador Energy Company, effective December 24, 2009 (1)
10.1
Purchase and Sale Agreement dated December 31, 2005 between Hallador Petroleum Company, as Purchaser and Yorktown Energy Partners II, L.P., as Seller relating to the purchase and sale of limited partnership interests in Savoy Energy Limited Partnership (2)
10.2
Letter of Intent dated January 5, 2006 between Hallador Petroleum Company and Sunrise Coal, LLC (3)
10.3
Subscription Agreement - by and between Hallador Petroleum Company and Yorktown Energy Partners VI, L.P., et al dated February 22, 2006. (2)
10.4
Subscription Agreements - by and between Hallador Petroleum Company and Hallador Alternative Assets Fund LLC, et al dated February 14, 2006. (3)
10.5
Continuing Guaranty, dated April 19, 2006, by Hallador Petroleum Company in favor of Old National Bank (6)
10.6
Collateral Assignment of Hallador Master Purchase/Sale Agreement, dated April 19, 2006, among Hallador Petroleum Company, Hallador Petroleum, LLLP, and Hallador Production Company and Old National Bank (6)
10.7
Reimbursement Agreement, dated April 19, 2006, between Hallador Petroleum Company and Sunrise Coal, LLC (6)
10.8
Membership Interest Purchase Agreement dated July 31, 2006 by and between Hallador Petroleum Company and Sunrise Coal, LLC. (7)
10.9
Subscription Agreements - by and between Hallador Petroleum Company and Yorktown Energy Partners VII, L.P., et al dated October 5, 2007 (7)
10.10
Purchase and Sale Agreement dated effective as of October 5, 2007 between Hallador Petroleum Company, as Purchaser and Savoy Energy Limited Partnership, as Seller (11)
10.11
First Amendment to Credit Agreement, Waiver and Ratification of Loan Documents dated June 28, 2007 by and between Sunrise Coal, LLC, Hallador Petroleum Company and Old National Bank (9)
10.12
Amended and Restated Continuing Guaranty, dated as of June 28, 2007, between Hallador Petroleum Company, Sunrise Coal, LLC, and Old National Bank. (10)
10.13
Hallador Petroleum Company Restricted Stock Unit Issuance Agreement dated as of June 28, 2007, between Hallador Petroleum Company and Victor P. Stabio(10)*
10.14
Hallador Petroleum Company Restricted Stock Unit Issuance Agreement dated as of July 19, 2007, between Hallador Petroleum Company and Brent Bilsland(11)*
10.15
Hallador Petroleum Company 2008 Restricted Stock Unit Plan. (12)*
10.16
Form of Amended and Restated Purchase and Sale Agreement dated July 24, 2008 to purchase additional minority interest from Sunrise Coal, LLC's minority members (13)
10.17
Form of Hallador Petroleum Company Restricted Stock Unit Issuance Agreement dated July 24, 2008 (13)*
10.18
Credit Agreement dated December 12, 2008, by and among Sunrise Coal, LLC, Hallador Petroleum Company as a Guarantor, PNC Bank, National Association as administrative agent for the lenders, and the other lenders party thereto. (14)

 
2740
 


10.19
Continuing Agreement of Guaranty and Suretyship dated December 12, 2008, by Hallador Petroleum Company in favor of PNC Bank, National Association (14)
10.20
Amended and Restated Promissory Note dated December 12, 2008, in the principal amount of $13,000,000, issued by Sunrise Coal, LLC in favor of Hallador Petroleum Company (14)
10.21
Form of Purchase and Sale Agreement dated September 16, 2009 (15)
10.22
Form of Subscription Agreement dated September 15, 2009 (15)
10.23
Form of Hallador Petroleum Company Restricted Stock Unit Issuance Agreement. (15)*
10.24
2009 Stock Bonus Plan(16)*
10.25
$165,000,000 Revolving Credit Facility (17)
14
Code ofOf Ethics For Senior Financial OfficersOfficers. (5)*
21.1
List of Subsidiaries (18)
23.1
Consent of EKSH, our auditors EKS&H LLLP (18)
23.2
Consent of Brock Engineering, LLC(18)
31
SOX 302 Certifications (18)
32
SOX 906 Certification (18)
95
Mine Safety Disclosure (18)
99
2013 SEC Reserve Report by Brock Engineering, LLC(18)
101Interactive data files.
---------------------------------------
(1)  IBR to Form 8-K dated December 31, 2009.
(10)  IBR to Form 8-K dated July 2, 2007.
(2)  IBR to Form 8-K dated January 3, 2006.
(11)  IBR to Form 10-KSB dated December 31, 2007.
(3 )
(3)  IBR to Form 8-K dated January 6, 2006.
(12)  IBR to March 31, 2007 Form 10-Q.
(4)  IBR to Form 8-K dated February 27, 2006.
(13)   IBR to Form 8-K dated July 24, 2008.
(5)  IBR to the 2005 Form 10-KSB.
(14)  IBR to Form 8-K dated December 12, 2008.
(6)  IBR to Form 8-K dated April 25, 2006.
(15)   IBR to Form 8-K dated September 18, 2009.
(7)  IBR to Form 8-K dated August 1, 2006.
(16)  IBR to Form S-8 dated December 1, 2009.
(8)   IBR to Form 10-QSB dated September 30, 2007.
(17)   IBR to Form 8-K dated October 18, 2012
(9)   IBR to Form 10-QSB dated June 30, 2007.
(18)  Filed herewith.
  
*Management contracts or compensatory plans. 



 
2841
 




SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
  HALLADOR ENERGY COMPANY
   
   
   
Date: March 6, 20132014 /s/W. ANDERSON BISHOP
       W. Anderson Bishop, CFO and CAO
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
 
 
   
/s/DAVID HARDIE
  
    David HardieChairmanDirectorMarch 6, 20132014
   
   
/s/VICTOR P. STABIO
  
    Victor P. StabioCEO and DirectorChairmanMarch 6, 20132014
   
   
/s/BRYAN LAWRENCE  
    Bryan LawrenceDirectorMarch 6, 20132014
   
   
/s/BRENT BILSLAND
  
    Brent BilslandPresident, CEO and DirectorMarch 6, 20132014
   
   
/s/JOHN VAN HEUVELEN  
    John Van Heuvelen DirectorMarch 6, 20132014
  
 










 
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