HALLADOR ENERGY CO - Annual Report: 2011 (Form 10-K)

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

form10k2011.htm

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, 2011 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”

Securities registered pursuant to Section 12(b) of the Exchange Act: NONE

Securities registered pursuant to Section 12(g) of the Exchange Act: Common Stock, $.01 par value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15 (d) of the Act. Yes o No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "larger accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

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 on June 30, 2011 was about $50 million based on the closing price reported that date by the NASDAQ of $9.59 per share.

As of February 29, 2012 we had 28,309,000 shares outstanding.

Portions of our information statement to be filed with the SEC in connection with our annual stockholders’ meeting to be held on April 19, 2012 are incorporated by reference into Part III of this Form 10-K.

PART 1

ITEM 1. BUSINESS.

General Development of Business

In December 2009 we changed our name from Hallador Petroleum Company to Hallador Energy Company. We are a Colorado corporation and were organized by our predecessor in 1949. About 77% of our stock is held by officers, directors and their affiliates. Our stock is thinly traded (average daily volume is about 16,000 shares) on the NASDAQ Capital Market listing under the symbol HNRG.

The largest portion of our business is devoted to underground 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 company with operations in Michigan. In late December 2010 we invested $2.4 million for a 50% interest in Sunrise Energy, LLC which then purchased existing gas reserves and gathering equipment from an unrelated third party with plans to develop and operate such reserves. 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 nat-gas prices. The primary reason we consummated this purchase was to protect our coal reserves from unwanted fracking by unrelated parties. We account for our investments in Savoy and Sunrise Energy using the equity method. 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. Occasionally, we participate in the drilling of oil and gas wells. See Item 7- MD&A on page 18 for a discussion of Savoy, our successful lease play in North Dakota and our ORRIs in Wyoming.

Our largest contributor to revenue and earnings is the Carlisle underground coal mine located in western Indiana. The Carlisle mine was in the development stage through January 31, 2007. Coal shipments began February 5, 2007.

Active Reserve (assigned) - Carlisle

Our coal reserves at December 31, 2011 assigned to the Carlisle mine were 46 million tons compared to beginning of year reserves of 46.7 million tons. Primarily through the execution of new leases, our reserve additions of 2.6 million tons replaced about 80% of our 2011 production of about 3.3 million tons.

In addition to the Allerton reserve discussed below, we are currently evaluating multiple mining projects which could add to our coal reserves by the end of 2012. Some of these projects are near the Carlisle mine and if they come to fruition we expect to utilize our existing wash plant and load-out facility.

New Reserve (unassigned) - Allerton

We have leased roughly 19,500 acres in Vermillion County, Illinois near the village of Allerton. Based on our reserve estimates we currently control 32.3 million tons of recoverable coal reserves; 15.8 million which are proven and 16 million which are probable. A considerable amount of our 19,500 acres of leases has yet to receive any exploratory drilling, thus we anticipate our controlled reserves to grow as we continue drilling in 2012. The permitting process was started in the summer of 2011 and we anticipate filing the formal permit with the state of Illinois and the appropriate Federal regulators during the second quarter of 2012. If the process proceeds smoothly, we anticipate receiving a mining permit in the first half of 2013. 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. Sunrise personnel have opened coal mines in this area in the past.

Full-scale mine development will not commence until there is proven market demand and we have a sales commitment.

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 is the first time we have sold coal to a customer as far as Jacksonville, Florida. We have no more contracts with JEA but are in discussion with other Florida utilities regarding such. We believe these discussions are the continuation of the trend of Illinois Basin (ILB) coal replacing Central Appalachia coal that traditionally supplied the southeast markets.

Only about 37% of our 2014 expected coal production is contracted for and we have no contracts extending past 2014. Of our 46 million tons of coal reserves assigned to the Carlisle mine, only 6.9 million tons are under contract; in other words about 85% of our reserves are uncommitted.

The table below illustrates the status of our current coal contracts:

Year	Contracted Tons	Average Price

2012	2,900,000	$42.35
2013*	2,900,000	40.14
2014*	1,100,000	46.34

________________

*For 2013 and 2014 we have a contract for 900,000 tons each year with one of our customers and we have agreed to reopen the contracted price during 2013. Each side has agreed to negotiate in good faith; however, if we can’t reach an agreed upon price, then our customer has the right to call the tons at the higher contracted price or if they don’t call the tons then we have the right to put the tons to them at the lower contracted price. For purposes of the table we used the lowest price option considering the current state of the coal markets.

In the short-run, the market for thermal coal in the United States faces a number of challenges. Unusually mild winter weather has reduced electricity generation and thus both coal burn and gas burn, resulting in a rapid build in coal inventories that now stand at greater than 180 million tons nationwide, an increase of more than 30 million tons from just three months ago. The mild weather, burgeoning inventories and prolific production of natural gas has recently driven the price of natural gas to decade lows, which has increased fuel switching in favor of gas and forced the price of thermal coals lower across all production basins. Regulatory uncertainties, particularly surrounding the recently delayed Cross-state Air Pollution Rule (CSAPR), and Maximum Achievable Control Technology (MACT), are causing utilities to defer coal purchasing decisions, and in some cases to retire coal-fired generating facilities.

That being said, two of our customers have advised us that their coal stockpiles are increasing. We have orally agreed with one of the two customers to store 300,000 tons of coal on our property from the summer of 2012 to the summer of 2013. We will continue to sell the coal as contracted to this customer. The risks and rewards of ownership will pass from us to them. We will be paid an additional storage fee on the stored tons. We continue to work with the other customer and their inventory issues; a possible solution may also include storing their contracted tons. At this time we are unsure as to the ultimate outcome of these discussions.

If our future cash mining costs remain in our historical range of $24-25/ton over the next two years and if our expected maintenance capital expenditures (cap ex) each year are in the $10-12 million range, we expect to generate ample amounts of cash flow.

We have two sister wash plants engineered to work together with an annual capacity of 3.5-3.9 million clean tons at current recoveries. We have the capability of expanding underground production to meet this capacity. If prices are favorable we will expand underground production.

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.

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.

Quality and volumes for the coal are stipulated in coal supply agreements and in some limited instances buyers have the option to vary annual or monthly volumes if necessary. Variations to the quality and volumes of coal may lead to adjustments in the contract price. Our coal supply agreements contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as heat content (British Thermal Units-Btus), moisture, sulfur and ash content.

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 certain underground mining equipment and electricity. The supplier base providing mining materials has been relatively consistent in recent years, although there has been some consolidation. Purchases of certain underground mining equipment are concentrated with one principle supplier; however, supplier competition continues to develop.

Carlisle Mine

The Carlisle mine is located in the ILB and has about 46 million tons of high-sulfur bituminous coal reserves. Our historical coal specifications for this mine are: 13.15 % moisture; 11,483 Btu; 8.63% ash; 3.02% SO2 and 5.27 lb SO2. Compared to other ILB mines, our reserves have lower chlorine (<0.10%) than the average ILB of 0.22%. The relatively low chlorine content makes it highly attractive to buyers given their desire to limit the corrosive effects in their power plants.

The ILB boasts several long-term trends that are expected to benefit coal producers in the region. Historically, ILB coal demand has outpaced supply for several years. This supply/demand dynamic is driven by an increase in scrubber retrofits, new coal-fired capacity coming on line and coal depletion in the Eastern Basins. The local Indiana supply/demand market dynamics, coupled with new pockets of demand from nearby domestic markets, should provide a strong long-term demand foundation for our coal. Over 95% of the electricity generated in Indiana comes from coal-fired plants. Only West Virginia is higher. The majority of Indiana coal is consumed in Indiana.

Outside of the local market, demand for ILB coal has been on the rise and is expected to continue for the foreseeable future. ILB coal is well positioned to supply other domestic markets, as Eastern U.S. coal providers with depleting reserves continue to seek higher prices in international markets.

Transportation Advantage

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 our Indiana customers. Long term, the CSX anticipates our coal being shipped to southeast markets via their railroad.

We sell our coal FOB the mine. Substantially all of our coal is transported by rail. Our mine is accessible by truck and is within 90 miles of nine coal-fired plants that have been retrofitted to burn our high-sulfur coal.

Coal Preparation

Coal extracted from Carlisle contains impurities such as rock and sulfur. We utilize a wash plant located at the mine to remove impurities from the coal and to insure our product meets contract specifications. Our wash plant allows us to treat the coal we extract from Carlisle to ensure a consistent quality.

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). These regions consumed about 63% of coal used in electric generation in 2008. 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

The U.S. has over 200 billion tons of recoverable coal reserves, representing about 94% of the domestic fossil fuel energy, according to the U.S. Geological Survey (USGS). This is about 27% of the world’s total proven reserves. The energy potential of American coal exceeds that of all the oil in the Middle East. The EIA (Energy Information Administration) estimates that current domestic recoverable coal reserves could supply enough electricity to satisfy domestic demand for 200 years. The U.S. is also the second largest coal producer in the world, exceeded only by China. Annual coal production in the U.S. has increased from 434 million tons in 1960 to about 1 billion tons in 2010, based on information provided by the EIA. Coal is the fastest growing fuel in the world. The majority of coal consumed in the United States is used to generate electricity, with the balance used by a variety of industrial users to heat and power foundries, cement plants, paper mills, chemical plants and other manufacturing and processing facilities. Metallurgical coal is predominately consumed in the production of metallurgical coke used in steelmaking blast furnaces. In 2010, coal-fired power plants produced approximately 45% of all electric power generation, more than natural gas and nuclear, the two next largest domestic fuel sources, combined. In 2010, 95% of US thermal coal consumption was by the electric power sector with the balance used in industrial and commercial applications.

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 (App), Northern App, Illinois Basin, Powder River Basin and the Western Bituminous region. The Central App Basin includes eastern Kentucky, Tennessee, Virginia and southern West Virginia. The Northern App Basin includes Maryland, Ohio, Pennsylvania and northern West Virginia. The Illinois Basin includes Illinois, Indiana and western Kentucky. The Powder River Basin is located in northeastern Wyoming and southeastern Montana. The Western Bituminous Basin 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. According to the National Mining Association (NMA), of the coal produced during 2010, ⅔ came from surface mines and ⅓ from underground mines.

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.

Competitive Pressures

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 in the United States. The five largest producers are estimated by the 2009 NMA Survey to have produced approximately 53% (based on tonnage produced) of the total United States production in 2009. The U.S. Department of Energy reported about 1,300 active coal mines in the United States in 2010, the latest year for which government statistics are available. Peabody Energy Corporation (NYSE:BTU) and Foresight Energy, a private company controlled by Chris Cline are probably the two largest operators in the ILB. While we sold about three million tons from our Carlisle mine, Peabody sold about 28 million tons from 12 mines (surface and underground) in the ILB during 2011. Demand for our coal by our principal customers is affected by many factors including:

•

the price of competing coal and alternative fuel supplies, including nuclear, natural gas, oil and renewable energy sources, such as hydroelectric power or wind;

•

coal quality;

•

transportation costs from the mine to the customer; and

•

the reliability of fuel supply.

Continued demand for our coal and the prices that we receive are affected by demand for electricity, environmental and government regulation, technological developments and the availability and price of competing coal and alternative fuel supplies.

Coal is the primary fuel source (about 45%) for electrical generation in the U.S. Despite capacity growth for other fuel sources of electricity, coal is still expected to provide the largest share of energy for U.S. electricity generation.

Natural Gas

One of the trends that cause us concern is the burning of natural gas to generate electricity in the U.S. Affordability plays a significant role in coal’s position as the most used fuel source in energy generation. In the U.S., coal has historically had a relatively lower delivered cost per million Btu (MMBtu) compared to other energy sources. The EIA projects coal prices to be $2.40 on a dollars per MMbtu basis.

Although coal has been and remains the major fuel for electricity generation in the U.S., natural gas has increased its share as a fuel in electrical generation in recent years. High natural gas prices in 2003 and 2004 made it economical for power generators to retrofit existing coal-burning units with scrubbers and low nitrogen oxide burner technology or switch to lower-sulfur coals in order to reduce emissions. Recently, however, natural gas substitution in electricity generation has increased. Natural gas spot prices declined sharply from about $13 per MMBtu in the summer of 2008 to current prices in the $2.50 per MMBtu range prompting some utilities to substitute natural gas for coal as fuel in electricity generation.

Gas producers have been arguing for some time that new sources of fuel, especially shale gas, have made it both plentiful and reliable. Furthermore, carbon dioxide emission from burning natural gas compared to coal is about 50% less. But residential and industrial consumers, from homeowners to power utilities, have been reluctant to increase their dependence on natural gas because of concerns about price volatility. This appears to be changing, due to a combination of factors. Huge new discoveries in the U.S. and Canada have greatly increased supplies, lowering prices. Big infrastructure build-outs in recent years have made it easier to move gas around to where it is needed, helping ease regional price spikes. Recent multi-billion deals by large domestic and foreign entities are the latest signs that these entities see U.S. natural gas, especially gas found in shale rock, as a giant resource. Gas producers hope these deals will help them convince federal officials and power executives that prices are entering a period of relative calm.

There are some that believe natural gas 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, natural gas would gain another advantage over coal since electricity from coal produces more carbon. Some natural gas producers believe that there is certainly the potential for natural gas producers and utilities to develop a new relationship that has not been possible historically.

Employees

Our coal operations currently employ 333 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 270 days of the year. The Carlisle mine is 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.

We don’t think it is necessary to discuss all the different laws and regulations that we are subject to. Suffice it to say, the coal industry in under attack by the current administration. If there is a change in administration resulting from the November 2012 elections that will be positive for the coal industry, if not, that would be negative.

Reclamation

The Carlisle mine began commercial production in February 2007 and is operating in compliance with all local, state, and federal regulations. We have no old mine properties to reclaim, other than the Howesville mine, which was operated for only eight months before it was closed in June 2006 due to safety concerns. During 2007, we finished Phase I of the reclamation of the Howesville mine. To reach final reclamation we must raise commercial crops for a period of five years.

Currently we do not operate any surface mines.

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.

Mine Health and Safety Laws

We are proud of our safety record. We comply with the rules and regulation issued by the Mine Safety and Health Administration (MSHA) and also state rules and regulations. We applaud all reasonable rules and regulation that promote mine safety and keep our miners out of harm’s way. Complying with these existing rules and proposed rules add to our mining costs.

Clean Air Act and Related Regulations

The federal Clean Air Act and similar state laws and regulations which regulate emissions into the air, affect coal mining, coal handling and processing, primarily through permitting and/or emissions control requirements.

The Clean Air Act also indirectly affects coal mining operations by extensively regulating the air emissions of the coal-fired electric power generating plants operated by our customers. Coal contains impurities, such as sulfur, mercury and other constituents, many of which are released into the air when coal is burned. Carbon dioxide, a greenhouse gas (GHG), is also emitted when coal is burned. Environmental regulations governing emissions from coal-fired electric generating plants could affect demand for coal as a fuel source and affect the volume of our sales. For example, the federal Clean Air Act places limits on sulfur dioxide, nitrogen dioxide, and mercury emissions from electric power plants.

The installation of additional control measures to achieve regulatory emission reductions makes it more costly to operate coal-fired power plants and could make coal a less attractive fuel. In order to meet the proposed new limits for sulfur dioxide emissions from electric power plants, many coal users need to install scrubbers, use sulfur dioxide emission allowances (some of which they may purchase), blend high sulfur coal with low sulfur coal or switch to low sulfur coal or other fuels. More strict emission limits mean few coals can be burned without the installation of supplemental environmental control technology in the form of scrubbers.

These types of regulations and requirements and proposed such regulations and requirements could significantly increase our customers’ costs and cause them to reduce their demand for coal, which may materially impact our results of operations.

Other

We have no significant patents, trademarks, licenses, franchises or concessions.

Other than the 333 Sunrise Coal employees in Indiana, our CEO, CFO, controller, geologist, land person and two part time administrative staff work in the Denver office.

Our Denver office is located at 1660 Lincoln Street, Suite 2700, Denver, Colorado 80264, phone 303.839.5504 and Sunrise Coal's corporate office is located at 1183 Canvasback Drive, Terre Haute, Indiana 47802, phone 812.299.2800. Terre Haute is approximately 70 miles west of Indianapolis. Our website is www.halladorenergy.com and Sunrise Coal’s is www.sunrisecoal.com.

ITEM 1A. RISK FACTORS.

Smaller reporting companies are not required to provide the information required by this item.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

Smaller reporting companies are not required to provide the information required by this item; however, there were none.

ITEM 2. PROPERTIES.

The Carlisle mine, located near the town of Carlisle in Sullivan County, Indiana, is an underground mine which 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.

Our current mine plan indicates 15,100 acres of mineable coal with an approximate 4' to 7' thickness in the project area. Of the 15,100 acres, 13,600 are currently under lease to Sunrise. The Indiana V seam has been extensively mined by underground and surface methods in the general area and is the most economically significant coal in Indiana.

Findings are based on generally accepted engineering principles and professional experience in the mining industry. All judgments are based on the facts that are available at this time.

Assigned Coal Reserve Estimates- Carlisle Mine

We estimate that, as of December 31, 2011, the Carlisle Mine had total recoverable reserves of approximately 46 million tons consisting of both proven (36 million) and probable (10 million) reserves. “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.

Unassigned New Coal Reserves – Allerton

See page three for a discussion of Allerton.

Our reserve estimates were prepared by Samuel Elder and Jacob Gennicks, two of our mining engineers. Mr. Elder is a licensed Professional Engineer in the State of Indiana and has over 25 years experience estimating coal reserves. Mr. Gennicks is a licensed Professional Engineer in the State of Indiana and Illinois and has three years experience estimating coal reserves.

The reserve estimates for all leased acres was made utilizing Carlson Mining 2009 (software developed by Carlson Software). To convert volumes of coal to an in-place tonnage, a weight of 80 pounds/cubic foot was used for both reserve areas. To convert Carlisle reserve to product tonnage, a 53% mine recovery and an average of 79% washed recovery (coal only recovery, no out-of- seam dilution included) were used.

Example: In-place tonnage x 53% x 79% = product tonnage.

To convert Allerton reserve to product tonnage, a 45% mine recovery and an average of 77% washed recovery (coal only recovery, no out-of- seam dilution included) were used.

Example: In-place tonnage x 45% x 77% = product tonnage.

Standards set forth by the USGS were used to place areas of the mine reserves into the Proven (measured) and Probable (indicated) categories. Under these standards, coal within 1,320' of a data point is considered to be proven, and coal within 1,320' to 3,960' is placed in the Probable category. All reserves are stated as a final salable product.

ADDITIONAL DISCLOSURES FOR THE CARLISLE MINE

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.

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. Approximately 84% of the total mine plan is currently under lease ("controlled"). 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.

The Carlisle mine has a dual-use slope for the main coal conveyor and the moving of supplies and personnel. There are two 8' diameter shafts at the base of the slope for mine ventilation. Two additional air shafts (8’ and 10.5’ diameter) were completed about three miles north of the original air shaft in 2009 to facilitate the mine expansion. The slope (9° or 15% grade) is 18' wide with concrete and steel arch construction. A 16’ hoist is now open (spring 2011) approximately four miles north of the main slope. The hoist is currently facilitating two production units by efficiently moving personnel and materials into the north main and north main addition areas of the reserve. All underground mining equipment is powered with electricity and underground compliant diesel.

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 is completed in 2012 the structure will handle disposal for roughly 36 million clean tons of coal.

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.

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;

	•	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.

ITEM 3. LEGAL PROCEEDINGS. None

ITEM 4. MINE SAFETY DISCLOSURES

See Exhibit 95 to this Form 10-K for a listing of our mine safety violations.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Our common stock is traded on the NASDAQ Capital Market under the symbol HNRG. Prior to May 27, 2010 we were traded on the OTC Bulletin Board under the symbol HPCO.OB. The following table sets forth the high and low closing sales price for the periods indicated:

	High		Low
2012
(January 1 through February 29, 2012)	$	10.45	$	9.54
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
2010
Fourth quarter		12.64		10.47
Third quarter		12.10		7.36
Second quarter		13.00		8.25
First quarter		9.80		7.50

During May 2010 we declared our first cash dividend of $0.10 per common share of which there were 27,782,028 outstanding. Furthermore, our board approved that the dividend would also apply to the 1,150,000 outstanding restricted stock units (RSUs) and to the 434,167 outstanding stock options on that date. The total cash payment for all the outstanding securities was about $2.9 million. During May 2011 we declared another special dividend of $0.12 per share. As was done last year, the dividend also applied to our outstanding RSUs and stock options. The total cash payment for all the outstanding securities was about $3.5 million. We evaluated our cash position and capital requirements and decided to declare another special cash dividend of $.14 per share payable in April 2012. The total payment, which also covers our outstanding RSUs and options, will be about $4.1million.

At February 29, 2012, we had 251 shareholders of record of our common stock; this number does not include the shareholders holding stock in "street name.” We estimate we have over 300 street name holders. On February 29, 2012 our stock closed at $10.10.

Equity Compensation Plan Information

On January 7, 2011 we allowed four Denver employees (non officers) an opportunity to relinquish 100% of their vested options (234,167) for 181,261 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 which was created in December 2009. Under such plan employees are allowed to relinquish shares to pay for their income taxes; accordingly, 41,645 shares were relinquished.

Currently we have 200,000 outstanding stock options to our CEO with an exercise price of $2.30. The options are fully vested and expire in April 2015.

At December 31, 2011 we had 636,000 RSUs outstanding and about 922,000 available for future issuance. Our RSU and stock option plans were approved by our BODs and collectively they and their affiliates control about 77% of our stock.

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 OPERATION.

Overview

The largest portion of our business is devoted to underground 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 company with operations in Michigan. In late December 2010 we invested $2.4 million for a 50% interest in Sunrise Energy, LLC which then purchased existing gas reserves and gathering equipment from an unrelated third party with plans to develop and operate such reserves. 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 nat-gas prices. The primary reason we consummated this purchase was to protect our coal reserves from unwanted fracking by unrelated third parties. We account for our investments in Savoy and Sunrise Energy using the equity method. 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. Occasionally, we participate in the drilling of oil and gas wells. Further below are discussions of Savoy, our successful lease play in North Dakota and our ORRIs in Wyoming.

Our largest contributor to revenue and earnings is the Carlisle underground coal mine located in western Indiana, about thirty miles south of Terre Haute. The Carlisle mine was in the development stage through January 31, 2007. Coal shipments began February 5, 2007.

Outlook

Headwinds created by low natural gas prices, mild weather, and weaker domestic economies impacted coal markets during the year, and market weakness continues as we enter 2012.

The current exceptionally mild winter has dramatically decreased demand for electricity: since October 2011, heating degree days are down by 17 percent compared to normal, and electricity demand is estimated to be down by 3.3 percent. This lack of demand is a major factor behind the current low near-term gas and coal prices. Unless there is a dramatic cold snap, these conditions are expected to persist until the summer. For 2012 we will continue to focus on maintaining our low cost structure and leasing and permitting new reserves.

We do see an increasing demand for coal produced in the ILB in the future. Demand for coal produced in the ILB is expected to grow at a rate faster than overall U.S. coal demand, due to ILB coal having higher heating content than PRB and lower cost structure than Central App 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 Central App cost structure that is leading to increased switching from Central App coal to ILB coal. Some fuel switching will also occur from PRB to ILB in newly scrubbed utilities located near ILB coal supply.

Growth in international coal import demand has resulted primarily from increased demand for thermal coal for electricity generation by emerging global economies, particularly by Asian countries in the Pacific market where coal is the primary fuel source for new power generation. We believe that the widening of the Panama Canal in 2014 should lower freight rates which would enhance coal exports to Asia.

In Europe, domestic coal supply has declined due to reduction in domestic production as a result of the region’s declining coal reserve base and a reduction in government subsidies for coal mining, particularly in Poland, Germany and Spain. Additionally, the International Atomic Energy Agency projects slower global growth in nuclear power capacity following the 2011 earthquake in Japan and related nuclear incident. Germany, in particular, has closed certain older facilities and is planning to shut down its remaining nuclear plants by 2022. Coal-fired generation is expected to meet a large portion of this additional demand. We believe that the decline in domestic production in Europe, coupled with an expected increase in coal-fired power generation, will result in an increase in thermal coal imports.

Due to the location of our coal mine, we expect to continue concentrating our efforts on supplying the domestic market. We expect as more coal is exported from the ILB, the coal that remains for the domestic market will increase in value.

As discussed further under “Competitive Pressures” on page nine, natural gas has increased its share as a fuel in electrical generation in recent years.

Yorktown Distribution

As previously disclosed, each time after we filed our 2011 Form 10-Qs for the first three quarters, we were advised by Yorktown Energy Partners VI, L.P., an investor for the last sixyears, that it had distributed shares of our common stock to its limited and general partners. First and second quarter distributions were 750,000 shares each and the third quarter distribution was 556,000 shares for a total of 2,056,000 shares. After the three distributions, Yorktown and its affiliates collectively hold about 13 million shares of our common stock representing about 46% of total shares outstanding.

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 distributions such as these will improve our liquidity and float. If and when we are advised of another Yorktown distribution after this Form 10-K is filed, we will timely report such on a Form 8-K.

Our consolidated financial statements should be read in conjunction with this discussion.

Prospective Information

See page four of this report for a table that illustrates the status of our current coal contracts.

Liquidity and Capital Resources

For 2011 we generated $61 million in cash from operations which enabled us to reduce our bank debt by $10 million, invest $24 million in the Carlisle mine, buy land for about $9 million for the Allerton project and pay a special dividend of $3.5 million. For 2012 we are scheduled to extinguish our bank debt in December and we anticipate our capital expenditures for the Carlisle mine falling to $10-12 million. We expect next year’s cash from operations to be lower due to the non-recurring gain of $10.7 million. Future cash flow from operations could be negatively impacted depending on the final outcome of our contract negotiations as discussed on page four of this report. Our cash flow from operations will also be negatively impacted by payments of state and federal income taxes.

We do not anticipate any liquidity issues in the foreseeable future. Eventually, when we develop a new reserve, we intend to incur additional debt and restructure our existing credit facility.

We have no material off-balance sheet arrangements.

During May 2010 we declared our first cash dividend of $0.10 per common share of which there were 27,782,028 outstanding. Furthermore, our board approved that the dividend would also apply to the 1,150,000 outstanding RSUs and to the 434,167 outstanding stock options on that date. The total cash payment for all the outstanding securities was about $2.9 million. During May 2011 we declared another special dividend of $0.12 per share. As was done last year, the dividend also applied to our outstanding RSUs and stock options. The total cash payment for all the outstanding securities was about $3.5 million. We evaluated our cash position and capital requirements and decided to declare another special cash dividend of $.14 per share payable in April 2012. The total payment, which also covers our outstanding RSUs and options, will be about $4.1million.

In late August 2010 we decided to drop the property insurance on our underground mining equipment. We feel comfortable with this decision as such equipment is allocated among four mining units spread out over eight miles. The historical cost of such equipment is about $93 million.

Project Update

New Reserve (unassigned) – Allerton

See page three of this report for a discussion of our Allerton project.

MSHA Reimbursements

Two of our major 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 a report which was reviewed by an outside consulting firm engaged by our customers. In January 2011 the two customers agreed to reimburse us about $1.9 million for costs incurred by us during 2008 and 2009. During those years we were not able to accurately estimate what the ultimate outcome of these reimbursable costs would be so we did not record them until we were certain of the amounts and certain of collection. Such amounts were recorded during the first quarter of 2011.

We submitted our incurred costs for 2010 in September of 2011 for $4 million. One of the customers paid $2 million in February 2012 and we continue discussions with the other customer. Accounting recognition for these 2010 reimbursements will be made in 2012.

Oil and Gas Properties

ORRI

We have an ORRI of about 2% on 22,500 acres and a 4% ORRI on 2,500 acres in Laramie County, Wyoming. This ORRI was obtained from leases we sold to SM Energy Company (formerly St. Mary Land) (NYSE:SM) in October 2008. This is a Niobrara oil shale play in the northern D-J Basin. During 2010, SM Energy drilled a discovery well (the Atlas 1-19) on this acreage. Through 2011 this well has produced 121,000 barrels of oil. During 2011 three additional wells were drilled and completed on our acreage with mixed results. It is uncertain how many more wills be drilled by SM. For 2011 we received $114,000 from these ORRI’s.

North Dakota Lease Play (Patriots Prospect)

We invested about $2.5 million in a lease play located in Slope, Hettinger and Stark counties of North Dakota which resulted in the purchase of about 10,600 net acres of oil and gas leases. On June 10, 2011, we signed a letter of intent with Chesapeake Energy Corporation (NYSE:CHK) to sell such acreage and on July 29, 2011, the deal closed. CHK purchased a 90% working interest for $13.2 million resulting in a pre-tax gain of about $10.6 million considering selling expenses and non-executive employee bonuses; due to some post-closing curative work about $1.5 million of the gain was recognized during the fourth quarter. We retained a 10% working interest and an approximate 3% average ORRI. If and when a well is proposed, we expect to participate in the drilling.

Results of Operations

For 2011, we sold 3,307,000 tons at an average price of $41.71/ton. For 2010 we sold 3,050,000 tons at an average price of $42.31/ton. Our average price for 2012, based on our contracts, is expected to be about $42.35/ton.

The 2011 “other income” is due to the MSHA reimbursements discussed above. The 2010 “other loss” of $772,000 was attributable primarily to our participating in the drilling of a dry hole in Michigan on a gas prospect developed by Savoy. Our share of the dry hole was about $1 million.

Operating costs and expenses averaged $23.31/ton in 2011 compared to $23.69 in 2010. We expect such costs to average $24-25/ton for 2012.

The increase in DD&A was due to additions to plant and equipment.

SG&A increased primarily due to higher expenses related to the new Allerton reserve, increases in certain salaries and increases in attending industry and investor conferences. Also we incurred higher curative costs to perfect our coal leases.

Our effective tax rate for 2011 and 2010 was in the 37-39% range and we expect such rate to be in the 32-36% range for 2012.

45% Ownership in Savoy

Savoy operates almost exclusively in Michigan. They have an interest in the Trenton-Black River Play in Southern Michigan. They hold 200,000 gross acres (about 100,000 net) in Hillsdale and Lenawee counties. During 2011 Savoy drilled 17 gross wells in this play of which 8 were dry and 9 were successful. During 2012 Savoy plans on drilling 25 additional wells in the play. Drilling locations in this play are identified based on the evaluation of extensive 3-D seismic shoots. Savoy operates their own wells and their working interest averages between 40 and 50% and their net revenue interest averages between 34 and 42%. Savoy’s net daily oil production currently averages about 805 barrels of oil and 340 (Mcf) of gas. Savoy has an interest in about 63 wells (25 net). LOE was about $8 per barrel of oil.

Savoy’s proved reserves are stated below and also in Note 5 to the financial statements. The pre-tax (Savoy is a partnership) present value of their future cash flows discounted at 10% (PV10) was about $97 million. Investors should note that the above numbers are to the 100%; our ownership in Savoy is about 45% so our share of the PV10 using SEC prices would be about $44 million.

The 2011 reserve report was prepared by Netherland, Sewell & Associates, Inc. (NSAI). See Note 5 for the qualifications of NSAI. The 2010 reserve report was prepared by Timothy Lovseth, our full-time geologist who has 30 years of experience in the oil and gas industry. Mr. Lovseth has no ownership in Savoy.

The table below illustrates the growth in Savoy over 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):

	2011		2010
Revenue:
Oil	$	25,781	$	11,138
Gas		566		760
NGLs (natural gas liquids)		868		227
Contract drilling		4,336		1,735
Gain on sale of unproved properties				2,225
Other		446		587
Total revenue		31,997		16,672
Costs and expenses:
LOE (lease operating expenses)		2,257		1,725
Severance tax		2,037		818
Contract drilling costs		2,559		1,445
DD&A (depreciation, depletion & amortization)		4,733		3,147
Geological and geophysical costs		1,973		2,632
Dry hole costs		1,852		808
Impairment of unproved properties		2,963		2,543
Other exploration costs		357		204
G&A (general & administrative)		1,166		1,116
Total expenses		19,897		14,438

Net income	$	12,100	$	2,234

The information below is not in thousands:
Oil production in barrels		283,000		149,000
4th quarter oil production in barrels		76,600		57,000
Gas production in Mcf		134,500		173,000
Average oil prices/barrel	$	91	$	75
Average gas prices/Mcf	$	4.20	$	4.38
Oil reserves (Bbls)		1,921,000		774,000
Gas reserves (Mcf)		2,491,000		787,000

PV 10 using SEC dictated average oil prices of $93.60 and $74	$97 million		$34 million

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. Since the Carlisle mine has only been in production since February 2007 we do not have a long history to rely on. The reserve estimates are used in the DD&A calculation, in our impairment test and in our internal cash flow projections. If these estimates turn out to be materially under or over-stated; our DD&A expense and impairment test may be affected. Furthermore, if our coal reserves are materially overstated our liquidity and stock price could be adversely affected.

We have analyzed our filing positions in all of the federal and state jurisdictions where we are required to file income tax returns, as well as all open tax years in these jurisdictions. We identified our federal tax return and our Indiana state tax return as “major” tax jurisdictions. None of our corporate tax returns have been examined in the last ten years. We were recently advised by the IRS that they will perform an examination of our 2009 and 2010 tax returns; such exam is to commence in mid-March 2012. We were also notified by Indiana tax representatives that they will examine our 2008-2010 tax returns; such exam is to commence this summer. We believe that our income tax filing positions and deductions will be sustained on audit and do not anticipate any adjustments that will result in a material change to our consolidated financial position. Therefore, no reserves for uncertain income tax positions have been recorded.

Our significant accounting policies are set forth in Note 1 to the Financial Statements.

New Accounting Pronouncements

None of the recent FASB pronouncements will have any material effect on us.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Smaller reporting companies are not required to provide the information required by this item.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Report of Independent Registered Public Accounting Firm	27

Consolidated Balance Sheet	28

Consolidated Statement of Operations	29

Consolidated Statement of Cash Flows	30

Consolidated Statement of Stockholders' Equity	31

Notes to Consolidated Financial Statements	32

Smaller reporting companies are not required to provide supplementary data

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, 2010 and 2011, and the related consolidated statements of operations, cash flows, and stockholders' equity for each of the years in the two year period ended December 31, 2011. 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, 2010 and 2011, and the results of their operations and their cash flows for each of the years in the two year period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

Ehrhardt Keefe Steiner & Hottman PC

March 2, 2012

Denver, Colorado

Consolidated Balance Sheet

As of December 31,

(in thousands, except per share data)


	2011			2010
ASSETS
Current assets:
Cash and cash equivalents	$	37,542		$	10,277
Certificates of deposit					1,291
Prepaid Federal income taxes					3,853
Accounts receivable		6,689			5,450
Coal inventory		1,863			2,100
Parts and supply inventory		2,202			2,411
Other		580			850
Total current assets		48,876			26,232

Coal properties, at cost:
Land, buildings and equipment		137,707			114,476
Mine development		66,614			59,351
		204,321			173,827
Less - accumulated DD&A		(42,493	)		(28,435	)
		161,828			145,392
Investment in Savoy		12,133			7,717
Investment in Sunrise Energy		3,297			2,375
Other assets (Note 8)		6,294			4,948
	$	232,428		$	186,664
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of bank debt	$	17,500			10,000
Accounts payable and accrued liabilities		10,411			8,809
Income taxes		5,125
Other		60			692
Total current liabilities		33,096			19,501

Long-term liabilities:
Bank debt, net of current portion					17,500
Deferred income taxes		31,100			17,435
Asset retirement obligations		2,276			1,150
Other		4,963			4,345
Total long-term liabilities		38,339			40,430
Total liabilities		71,435			59,931
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; 28,309 and 27,924 outstanding, respectively		283			279
Additional paid-in capital		85,984			84,073
Retained earnings		74,685			42,381
Accumulated other comprehensive income		41
Total stockholders' equity		160,993			126,733
	$	232,428		$	186,664

See accompanying notes.

Consolidated Statement of Operations

For the years ended December 31,

(in thousands, except per share data)

	2011		2010
Revenue:
Coal sales	$	137,998	$	129,003
Gain on sale of unproved oil and gas properties		10,653
Equity income - Savoy		5,476		1,005
Equity income - Sunrise Energy		922
Other income (loss) (Note 8)		2,305		(772	)
		157,354		129,236
Costs and expenses:
Operating costs and expenses		77,094		72,527
DD&A		14,096		11,818
Coal exploration costs		1,132		780
SG&A		7,004		5,556
Interest		1,288		1,926
		100,614		92,607

Income before income taxes		56,740		36,629

Less income taxes:
Current		7,266		885
Deferred		13,665		13,369
		20,931		14,254

Net income	$	35,809	$	22,375

Net income per share:
Basic	$	1.27	$	.81
Diluted	$	1.25	$	.78

Weighted average shares outstanding:
Basic		28,135		27,790
Diluted		28,694		28,571

See accompanying notes.

Consolidated Statement of Cash Flows

For the years ended December 31,

(in thousands)

	2011			2010
Operating activities:
Net income	$	35,809		$	22,375
Gain on sale		(10,653	)
Deferred income taxes		13,665			13,369
Equity income – Savoy and Sunrise Energy		(6,398	)		(1,005	)
Cash distributions from Savoy		1,060
DD&A		14,096			11,818
Change in fair value of interest rate swaps		(632	)		(712	)
Stock-based compensation		2,331			2,194
Other		576
Taxes paid on vesting of RSUs		(1,661	)		(746	)
Change in current assets and liabilities:
Accounts receivable		221			(163	)
Coal inventory		236			66
Income tax accounts		8,978			(2,807	)
Accounts payable and accrued liabilities		1,751			1,415
Other		1,341			(259	)
Cash provided by operating activities		60,720			45,545
Investing activities:
Proceeds from sale of unproved oil and gas properties		13,195
Capital expenditures for coal properties		(32,995	)		(34,714	)
Capital expenditures for unproved oil and gas properties		(1,710	)		(915	)
Investment in Sunrise Energy					(2,375	)
Investment in Savoy					(453	)
Change in CDs		1,291			2,167
Marketable securities		(2,257	)
Other		1,284			(752	)
Cash used in investing activities		(21,192	)		(37,042	)
Financing activities:
Payments of bank debt		(10,000	)		(10,000	)
Dividends		(3,505	)		(2,937	)
Stock option buy-out					(679	)
Tax benefit from stock-based compensation		1,242			327
Other					(163	)
Cash used in financing activities		(12,263	)		(13,452	)
Increase (decrease) in cash and cash equivalents		27,265			(4,949	)
Cash and cash equivalents, beginning of year		10,277			15,226
Cash and cash equivalents, end of year	$	37,542		$	10,277

Cash paid for interest	$	1,508		$	2,255
Cash paid for income taxes	$	100		$	4,400
Changes in accounts payable for coal properties	$	(358	)	$	(2,088	)

See accompanying notes.

Consolidated Statement of Stockholders’ Equity

(in thousands)

	Shares			Common Stock		Additional Paid-in Capital			Retained Earnings			AOCI*		Total
Balance January 1, 2010		27,782		$	277	$	85,245		$	23,105				$	108,627

Stock issued to board member for director services		9			1		99								100
Stock-based compensation							2,194								2,194
Stock issued on vesting of RSUs		133			1										1
Taxes paid on vesting of RSUs							(746	)							(746	)
Tax benefit from stock-based compensation							327								327
Stock option buy out for cash							(679	)							(679	)
Reduction in deferred tax asset resulting from Sunrise acquisition							(2,367	)							(2,367	)
Cash distributions to former noncontrolling interests for personal income taxes										(162	)				(162	)
Dividends										(2,937	)				(2,937	)
Net income										22,375					22,375
Balance December 31, 2010		27,924		$	279	$	84,073		$	42,381				$	126,733

Stock issued to board member for director services		11					100								100
Stock-based compensation							2,231								2,231
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
Increase in value of marketable securities available for sale, net of taxes												$	41		41
Dividends										(3,505	)				(3,505	)
Net income										35,809					35,809

Balance December 31, 2011		28,309		$	283	$	85,984		$	74,685		$	41	$	160,993

See accompanying notes.

Net income	$35,809
OCI	41
Comprehensive income	$35,850

*Accumulated Other Comprehensive Income

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 an underground mine 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 in natural gas operations in the same vicinity as our coal mine. We purchased our interest in Sunrise Energy in December 2010.

Reclassification

To maintain consistency and comparability, certain amounts in the 2010 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 mines, and include reclamation of support facilities, refuse areas and slurry ponds.

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% discount rate.

Federal and state laws require that mines be reclaimed to their previous condition 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:

	2011		2010

Balance beginning of year	$	1,150	$	922
Accretion		76		66
Change in cost estimate
Additions		1,050		162
Balance end of year	$	2,276	$	1,150

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 is 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 outstanding stock options and 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.

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, 2011, we are committed to supply to three customers about 7 million tons of coal during the next three years. These contracts represent about 15% of our recoverable reserves for the Carlisle mine. During 2011 and 2010, three of our customers accounted for 90% or more of our sales: for 2011 one customer accounted for 43%, the second for 29%, and the third for 17%; for 2010 one customer accounted for 45%, the second for 36%, 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.

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) 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:

	2011			2010
Expected amount	$	19,859		$	12,820
State income taxes, net of federal benefit		2,950			1,808
Other		(1,878	)		(374	)
	$	20,931		$	14,254

The deferred tax assets and liabilities resulting from temporary differences between book and tax basis are comprised of the following at December 31:

	2011			2010
Long-term deferred tax assets:
AMT credit carryforwards	$	1,137		$	1,162
Stock-based compensation		596			113
Investment in Savoy		960			1,575
Oil and gas properties		1,540			873
Net long-term deferred tax assets		4,233			3,723
Long-term deferred tax liabilities:
Coal properties		(35,333	)		(21,158	)
Net deferred tax liability	$	31,100		$	17,435

For financial accounting purposes the 2009 Sunrise Coal buyout was treated as an equity transaction among members of a controlled group. For income tax purposes we were able to increase our tax basis in the coal properties and will receive future tax deductions; accordingly, a deferred tax asset of $13 million was recognized with the credit recorded directly to additional paid-in capital. Upon further analysis, in preparing the 2010 tax provision we determined that the tax basis of the incremental assets acquired was less than that originally calculated. As such, in 2010, we reduced our deferred tax assets by $2.37 million with an offset to additional paid-in capital.

We have AMT credit carryforwards of about $1 million.

(3) Stock Compensation Plans

Restricted Stock Units

At December 31, 2011 we had 636,000 Restricted Stock Units (RSUs) outstanding and about 922,000 available for future issuance. The outstanding RSUs have a value of about $6.4 million based on our current stock price of about $10. During April 2010 we issued 126,500 RSUs with cliff vesting over three years. On the date of issuance of the RSUs our stock was selling for $8.40. During 2011, 30,000 RSUs were granted with cliff vesting over three years; our stock closed at about $11 on grant date. We expect 268,000 RSUs to vest during 2012 under our current vesting schedule. Every two years we consider granting RSUs to our mine managers; we expect to issue grants in 2012 but have yet to decide the amount.

During December 2011 and 2010, 195,000 RSUs vested each year. On vesting date the shares had a value of about $2 million for 2011 and about $2.3 million for 2010. Under our RSU plan participants are allowed to relinquish shares to pay for their required minimum statutory income taxes.

Stock based compensation expense for 2011 and 2010 was about $2.2 million for each year. For 2012 based on existing RSUs outstanding, stock based compensation expense will be about $2.1 million.

Stock Options

On January 7, 2010 we allowed four Denver employees (non officers) a one-time opportunity to relinquish 1/3 of their vested options (115,833) for cash of $679,000; the intrinsic value on such date. This transaction was treated as a charge to equity. On January 7, 2011 we allowed the same four Denver employees (non officers) the opportunity to exchange their remaining vested options (234,167) for 181,261 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 are allowed to relinquish shares to pay for their required minimum statutory income taxes.

Currently we have 200,000 outstanding stock options to our CEO with an exercise price of $2.30. The options are fully vested and expire in April 2015.

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, about 140,000 shares were issued. Currently, we have about 86,000 shares left in such plan.

(4) Notes Payable

In December 2008, we entered into a new loan agreement with a bank consortium that provides for a $40 million term loan and a $30 million revolving credit facility. At December 31, 2011, we owed $17.5 million on the term loan and nil on the revolver. The debt matures in December of 2012. We pay a .5% commitment fee on the unused revolver. Substantially all of Sunrise's assets are pledged under this loan agreement and we are the guarantor. The loan agreement requires customary covenants, required financial ratios and restrictions on distributions. Closing costs on this loan agreement were about $1.2 million and are being amortized using the effective interest method over its term which ends near the end of 2012. The current interest rate is LIBOR-one month (0.25%) plus 2.50% or 2.75%.

Considering our two interest rate swap agreements, commitment fees and amortization of the closing costs, our effective interest rates for 2011 and 2010 were about 6.6% each year. One of the swaps expired in December 2011 and the other will expire in July 2012. Assuming interest rates remain stable, we expect our interest rate, not including fees and the amortization of the closing costs, to be about 3% for the last half of 2012. The recorded value of our bank debt approximates fair value as it bears interest at a floating rate.

We expect to negotiate a new loan agreement with our banks sometime before the end of the year.

(5) Equity Investment in Savoy

We own a 45% interest in Savoy Energy L.P., a private company engaged in the oil and gas business primarily in the State 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

	2011		2010
Current assets	$	16,200	$	9,103
Oil and gas PP&E, net		17,973		15,978
Other		2,152		2,048
	$	36,325	$	27,129

Total liabilities	$	9,469	$	10,004
Partners' capital		26,856		17,125
	$	36,325	$	27,129

Condensed Statement of Operations

	2011			2010
Revenue	$	31,997		$	14,447
Gain on sale of unproved properties					2,225
Expenses		(19,897	)		(14,438	)
Net income	$	12,100		$	2,234

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:

	2011
Unproved property acquisition	$	1,202
Development		1,024
Exploration		3,990
Total	$	6,216

	Oil (Bbls)			NGLs (Bbls)			Natural Gas (Mcf)

January 1, 2011		350			6			356
Extensions and discoveries		509			21			689
Production		(128	)		(6	)		(61	)
Revisions to previous estimates		138			22			143
December 31, 2011		869			43			1,127

Proved developed reserves		361			22			438
Proved undeveloped reserves		508			21			689

	Proved Developed			PUDs			Total Proved
Future cash flows:
Oil	$	33,760		$	47,619		$	81,379
NGLs		1,452			1,435			2,887
Gas		2,170			3,199			5,369
Total cash flows		37,382			52,253			89,635
Future production costs		(10,866	)		(12,122	)		(22,988	)
Future development costs		(385	)		(5,196	)		(5,581	)
Future income tax (none since Savoy is a pass-through entity for income tax purposes)		0			0			0
Future net cash flows		26,131			34,935			61,066
10% annual discount for estimated timing of cash flows		(6,106	)		(10,870	)		(16,976	)
Standardized measure of discounted future net cash flows	$	20,025		$	24,065		$	44,090

Beginning of year	$	15,496
Sale of oil and gas produced, net of production costs		(10,374	)
Net changes in prices and production costs		4,806
Extension, discoveries and improved recoveries		24,066
Revisions of previous quantity estimates		8,547
Accretion of discount		1,549
End of year	$	44,090

Average wellhead prices
Oil (per Bbl)	$	93.60
NGLs (per Bbl)	$	66.95
Gas (per Mcf)	$	4.76

The 2011 reserve estimates shown above have been independently evaluated by Netherland, Sewell & Associates, Inc. (NSAI), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical person primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein is Mr. G. Lance Binder. Mr. Binder has been practicing consulting petroleum engineering at NSAI since 1983. Mr. Binder is a Licensed Professional Engineer in the State of Texas (No. 61794) and has over 33 years of experience in the estimation and evaluation of reserves. He graduated from Purdue University in 1978 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 Information 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.

(6) Equity Investment in Sunrise Energy

In late December 2010 we invested $2.4 million for a 50% interest in Sunrise Energy, LLC which then purchased existing gas reserves and gathering equipment from an unrelated third party with plans to develop and operate such reserves. 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 nat-gas prices. The primary reason we consummated this purchase was to protect our coal reserves from unwanted fracking by unrelated parties. They use the successful efforts method of accounting. We account for our interest using the equity method of accounting. Operations for 2010 were not material.

Below (in thousands) to the 100% is a condensed balance sheet at December 31, 2011 and a condensed statement of operations for the year then ended. Sunrise Energy’s proved oil and gas reserves are not material.

Condensed Balance Sheet

	2011

Current assets	$	1,916
Oil and gas properties, net		6,236
	$	8,152

Total liabilities	$	1,558
Members' capital		6,594
	$	8,152

Condensed Statement of Operations

	2011

Revenue	$	3,951
Expenses		(2,107	)
Net income	$	1,844

(7) 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. Our 2011 costs for the 401(k) matching were about $458,000 and our costs for health benefits were about $3.1 million. Our 2010 costs for the 401(k) matching were about $320,000 and our costs for health benefits were about $2.1 million. The 2011 amortized costs for the Deferred Bonus Plan were about $254,000 and the 2010 amortized costs were about $180,000. The costs for the production bonus plan were $910,000 in 2011 and $328,000 in 2010.

Our mine employees are also covered by workers’ compensation and such costs for 2011 and 2010 were about $1.3 million and $1.5 million, 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 include 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 employee 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 are adequate. We have a safety conscious work force and our worker’s compensation injuries have been minimal. Our mine has been in operation for about five years.

(8) Other Long-term Assets and Other Income (loss)

	2011			2010
Long-term assets:
Oil and gas properties	$	336		$	1,744
Advance coal royalties		3,205			1,863
Deferred financing costs, net		295			616
Marketable equity securities available for sale (restricted)*		2,326
Miscellaneous		132			725
	$	6,294		$	4,948
*Held by Sunrise Indemnity, Inc., our wholly-owned captive insurance company.

Other income (loss):
MSHA reimbursements**	$	1,900
Exploration and dry hole costs		(677	)	$	(1,302	)
Oil and gas sales, net of expenses		231			172
Miscellaneous		851			358
	$	2,305		$	(772	)

**See “MSHA Reimbursements” in our MD&A section for a discussion of the $1.9 million.

(9) Self Insurance

(10) Gain on Sale

See “North Dakota Lease Play” in our MD&A section for a discussion of the $10.7 million gain on sale.

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, 2011.

There has been no change in our internal control over financial reporting during the quarter ended December 31, 2011 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 Ehrhardt Keefe Steiner & Hottman PC (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 2012.

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.

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)
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)*
14	Code Of Ethics For Senior Financial Officers. (5)
21.1	List of Subsidiaries (17)
23.1	Consent of EKSH, our auditors (17)
23.2	Consent of Netherland, Sewell & Associates, Inc. (17)
31	SOX 302 Certifications (17)
32	SOX 906 Certification (17)
95	Mine Safety Disclosure (17)
99	Report of Netherland, Sewell & Associates, Inc. (17)

---------------------------------------

(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 ) 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) Filed herewith.
(9) IBR to Form 10-QSB dated June 30, 2007.

* Management contracts or compensatory plans.

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 2, 2012		/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 Hardie	Chairman	March 2, 2012


/s/VICTOR P. STABIO
Victor P. Stabio	CEO and Director	March 2, 2012


/s/BRYAN LAWRENCE
Bryan Lawrence	Director	March 2, 2012


/s/BRENT BILSLAND
Brent Bilsland	President and Director	March 2, 2012


/s/JOHN VAN HEUVELEN
John Van Heuvelen	Director	March 2, 2012