- Annual Report (10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

[ x ]	ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended: December 31, 2009 OR
[ ]	TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	Commission file number: 0-14731

	HALLADOR ENERGY COMPANY
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		Fax: 303.832.3013

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 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.

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  No 

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, 2009 was about $13 million based on the closing price reported that date by the OTC Bulletin Board of $5.50 per share.

As of March 3, 2010 we had 27,782,028 shares outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: NONE

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. Over 86% of our stock is closely held; see Item 12 of this Form 10-K for a listing of our major shareholders. Our stock is thinly traded on the OTC Bulletin Board under the symbol HPCO. On January 25, 2010, we applied for a NASDAQ Capital Market listing and reserved the trading symbol of HNRG.

In late 2006, we concluded to deemphasize our oil and gas operations and concentrate our efforts in the coal business. During 2007 and 2008 we sold substantially all of our oil and gas properties though we still own a 45% equity interest in Savoy Energy, L.P., a private oil and gas company which has operations in Michigan. Occasionally, we continue to participate in the drilling of oil and gas wells. We also lease oil and gas mineral rights with the intent to sell the prospect to third parties and retain an overriding royalty interest (ORRI). See page 14 for a further discussion of our ORRI in Wyoming and of Savoy.

Our primary operating property 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.

Our coal reserves at the beginning of 2009 assigned to the Carlisle mine were 43.4 million tons and the end of year reserves were 47.3 million tons. Primarily through the execution of new leases, our reserve additions of 6.5 million tons more than offset our 2009 production of about 2.6 million tons.

We are currently evaluating multiple mining projects with the goal of doubling our coal reserves by the end of 2011. We are currently testing a certain reserve and if the results prove favorable we expect to have a permitted reserve by the end of 2012. We should know more about the feasibility of this reserve during the second or third quarter of 2010.

Our Carlisle mine is very productive and has strong EBITDA . We believe our focus on productivity has helped contribute to our strong EBITDA. Our strategic investment in equipment and technology has increased the efficiency of our operations, which we believe reduces our costs and provides us with a competitive advantage.

Our Coal Contracts

Over the past three years we sold over 95% of our coal to three investment-grade customers. We have strong 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). For each of the next four years over 85% of our coal is contracted with these three customers at average prices over $40/ton. If our future cash mining costs remain in our historical range of $24-25/ton over these four years we expect to generate ample amounts of cash flow.

Only about 37% of our 2014 expected coal production is contracted for and we have no contracts extending past 2014. Of our 47 million tons of coal reserves assigned to the Carlisle mine, only 12.8 million tons are under contract; in other words about 70% of our reserves are uncommitted.

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

Year	Contracted Tons	Average Price
2010	3,000,000	$41.60
2011	2,900,000	41.65
2012	2,900,000	42.15
2013*	2,900,000	38.90-44.20
2014*	1,100,000	45.20-57.45

________________

*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 range of the two prices.

We have two sister wash plants engineered to work together with a capacity of 3.4 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.

Our revenue depends on the sales price for our coal. The pricing environment for domestic steam coal during 2009 weakened from the relatively strong pricing experienced throughout much of 2008. Near the end of 2008 and continuing into 2009, coal prices dropped drastically due to decreased demand for steam coal caused by high inventory levels at utilities.

As 2010 begins, prospects for the thermal coal market have begun to improve. A prolonged period of severe winter weather throughout much of the United States increased electricity generation while at the same time interrupting coal production and transportation logistics. Relative to conditions in 2009, economic recovery is widely anticipated in 2010 which should lead to increased electricity generation, particularly in heavily industrialized regions of the country that rely on low-cost, coal-fired electricity. In addition, further coal production cutbacks in Appalachia mines appear probable in 2010 driven by the roll-off of higher priced legacy contracts that could make certain mines uneconomical. In light of these trends, utilities’ coal inventories are anticipated to return to more normal levels by the second half of 2010. This market improvement is reflected in thermal coal spot prices which have increased recently and in coal futures prices which point to rising prices for the foreseeable future.

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-Btu), 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 Illinois Basin (IB) and has about 47.3 million tons of high-sulfur bituminous coal reserves. Our quality specifications for salable product are: < 16% moisture; > 11,200 Btu; < 10% ash; and < 6.5 LB SO 2 . Compared to other IB mines, our reserves have lower chlorine (<0.10%) than the IB average of 0.22%. The relatively low chlorine content of our coal makes it highly attractive to coal buyers given their desire to limit the corrosive effects of chlorine in their power plants.

The Illinois Basin boasts several long-term trends that are expected to benefit coal producers in the region. Historically, IB 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 IB and 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 Kentucky and West Virginia are higher. The majority of Indiana coal is consumed in Indiana.

Outside of the local market, demand for IB coal has been on the rise and is expected to continue for the foreseeable future. IB 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. New MSHA (Mine Safety and Health Administration) regulations, the extreme difficulty of obtaining permits to open surface mines, the current negative bias by the misinformed toward any fuel supply that emits carbon dioxide have combined to limit the near-term level of coal production capacity in the region.

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. Over 95% of our coal is transported by rail. Our mine is also accessible by road. Our mine 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

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 Illinois Basin 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. The price increase combined with the assurance from the U.S. government that the utility industry would remain predominantly regulated caused utility companies to begin investing in scrubbers on a large scale. With scrubbers, the Illinois Basin has reopened as a significant fuel source for utilities and has enabled them to burn lower cost, high sulfur coal.

The Illinois Basin (IB) consists of coal mining operations covering more than 50,000 square miles in Illinois, Indiana and Western Kentucky. The IB 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

Coal in the U.S. is primarily used as a fuel source for the generation of electricity, representing 93% of all coal consumed in 2008. About 2% of coal is consumed by coke plant blast furnaces in the steel production process while the remainder is consumed in industrial plants and by other end consumers. According to the Energy Administration Agency of the U.S. Department of Energy (EIA), coal consumption for use in electrical power generation has increased from 92 million tons in 1950 to 1,042 million tons in 2008.

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 U.S. Department of Energy 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 1.2 billion ton in 2008, based on information provided by the EIA. Coal is the fastest growing fuel in the world.

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 both surface and underground mining methods. According to the National Mining Association (NMA), 70% of coal was produced in surface mines and 30% from underground mining during 2008.

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 (room-and-pillar) 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 feet wide and the pillars are rectangular in shape measuring 40’x40’. 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 coal industry is intensely competitive. The most important factors on which we compete are coal quality, transportation costs from the mine to the customer and the reliability of supply. Most of our competitors are larger than us, have greater financial resources and larger reserve bases. Peabody Energy Corporation (NYSE:BTU) is the largest operator in the Illinois Basin. While we sold 2.6 million tons from our Carlisle mine, Peabody sold 31 million tons from 13 mines (surface and underground) in the IB during 2009.

Coal is the primary fuel source (about 50%) 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. Based on EIA forecasts, coal-fired generation as a percent of total electricity output is expected to modestly decrease to 47% in 2030.

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. During August 2009, the delivered cost of coal to electrical plants was $2.22 per MMBtu, considerably lower than the delivered cost for natural gas of $4.09 per MMBtu.

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 below $4 per MMBtu as of November 30, 2009, 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%. 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. Exxon Mobil Corp.’s decision to buy one of the largest U.S. gas producers, XTO Energy, is the latest sign that deep-pocketed oil and gas corporate giants see U.S. natural gas, especially gas found in shale rock, as a giant resource. Gas producers hope the Exxon deal will help them convince federal officials and power executives that prices are entering a period of relative calm. The EIA projected in mid December that natural gas prices would remain below $7 per MMBtu through 2025. The power utility industry in particular has been reluctant to depend too much on natural gas. The last time it built an inordinate amount of gas-fired power plants, in the 1990s, the price rose steeply partly in response to the new demand, driving many companies out of business.

Exxon and others believe that 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. In early December 2009, Progress Energy said it would shutter 11 coal-fired plants over the next eight years and replace them with gas units. The EIA predicted in early December 2009 that natural gas will account for 46% of all power plant additions from 2008 to 2035. 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 about 300 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 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 to guarantee performance or payment of certain long-term obligations, including mine closure and reclamation costs.

Reclamation

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

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 data 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 or even years 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

Stringent safety and health standards have been imposed by federal legislation since Congress adopted the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health Act of 1977 significantly expanded the enforcement of safety and health standards and imposed comprehensive safety and health standards on all aspects of mining operations. In addition to federal regulatory programs, the state in which we operate also has programs for mine safety and health regulation and enforcement. In reaction to several mine accidents in recent years, federal and state legislatures and regulatory authorities have increased scrutiny of mine safety matters and passed more stringent laws governing mining. For example, in 2006, Congress enacted the Mine Improvement and New Emergency Response Act of 2006 (MINER Act). The MINER Act imposes additional obligations on coal operators including, among other things, the following:


	•	development of new emergency response plans that address post-accident communications, tracking of miners, breathable air, lifelines, training and communication with local emergency response personnel;

	•	establishment of additional requirements for mine rescue teams;

	•	notification of federal authorities in the event of certain events;

	•	increased penalties for violations of the applicable federal laws and regulations; and

	•	requirement that standards be implemented regarding the manner in which closed areas of underground mines are sealed.

Climate Change

Global climate change concerns have a potentially far-reaching impact upon our business and results of operations. Concerns over measurements, estimates and projections of global climate change, particularly global warming, have resulted in widespread calls for the reduction, by regulation and voluntary measures, of the emission of greenhouse gases, which include carbon dioxide and methane. These measures could impact the market for our coal, increase our own energy costs and affect the value of our coal reserves. The United States has not ratified the Framework Convention on Global Climate Change, commonly known as the Kyoto Protocol, which would require our nation to reduce greenhouse gas emissions to 93% of 1990 levels by 2012. The United States is participating in international discussions to develop a treaty or other agreement to require reductions in greenhouse gas emissions after 2012 and has signed the Copenhagen Accord, which includes a non-binding commitment to reduce greenhouse gas emissions.

The U.S. Congress is considering a variety of legislative proposals which would restrict and/or tax the emission of greenhouse gases from the combustion of coal and other fuels and which would mandate or encourage the generation of electricity by new facilities that do not use coal.

Global warming concerns have prompted political debate regarding greenhouse gas (GHG) reductions, including carbon emissions generated by coal-fired power plants. The proposed American Clean Energy and Security Act of 2009 (ACES) includes provisions requiring retail electricity suppliers to meet 20% of their demand through renewable electricity, establishing a cap-and-trade system for GHG emissions and setting goals for reducing such emissions from covered sources by 83% of 2005 levels by 2050. Coal demand will be affected if the ACES is passed, as a cap-and-trade system would increase the cost of coal for the end user.

A step toward potential federal restriction on greenhouse gas emissions was taken on December 7, 2009 when the EPA issued its so-called Endangerment Finding in response to a decision of the Supreme Court of the United States. The EPA found that the emission of six greenhouse gases, including carbon dioxide (which is emitted from coal combustion) and methane (which is emitted from coal beds) may reasonably be anticipated to endanger public health and welfare. Based on this finding, EPA defined the mix of these six greenhouse gases to be “air pollution” subject to regulation under the Clean Air Act. Although EPA has stated a preference that greenhouse gas regulation be based on new federal legislation rather than the existing Clean Air Act, many sources of greenhouse gas emissions may be regulated without the need for further legislation. The EPA has already proposed regulations that would impact major stationary sources of greenhouse gas emissions, including coal-fired power plants that could come into effect as early as March 2010.

In addition to materially adversely impacting our markets and the demand for our coal, regulations enacted due to climate change concerns could affect our operations by increasing our costs. Our energy costs could increase and we may have to incur higher costs to control emissions of carbon dioxide, methane or other pollutants from our operations.

While advocating for comprehensive federal legislation, many states have adopted measures, sometimes as part of a regional collaboration, to reduce greenhouse gases generated within their own jurisdiction. These measures include emission regulations, including regional cap and trade programs, mandates for utilities to generate a portion of their electricity without using coal and incentives or goals for generating electricity using renewable resources. Some municipalities have also adopted similar measures. Even in the absence of mandatory requirements, some entities are electing to purchase electricity generated by renewable resources for a variety of reasons, including participation in programs calling for voluntary reductions in greenhouse gas emissions.

Passage of additional state or federal laws or regulations regarding greenhouse gas emissions or other actions to limit greenhouse gas emissions could result in fuel switching, from coal to other fuel sources, by electric generators. Such laws and regulations could, for example, include mandating decreases in greenhouse gas emissions from coal-fired power plants, imposing taxes on greenhouse gas emissions, requiring certain technology to capture and sequester greenhouse gases from new coal-fired power plants and encouraging the production of non-coal-fired power plants. Political and regulatory uncertainty over future emissions controls have been cited as major factors in decisions by power companies to postpone new coal-fired power plants. If measures such as these or other similar measures, like controls on methane emissions from coal mines, are ultimately imposed on the coal industry by federal or state governments

or pursuant to international treaty, our operating costs may be materially and adversely affected. Similarly, alternative fuels (non-fossil fuels) could become more attractive than coal in order to reduce greenhouse gas emissions, which could result in a reduction in the demand for coal and, therefore, our revenues.

Clean coal and low carbon technology could mitigate any adverse affects from GHG legislation. Carbon capture and storage (CSS), the injection of carbon into geological formations for long-term storage, would greatly reduce the amount of carbon emissions from coal-fired power plants. The use of this technology is increasing globally, including in the U.S. The geology of the Illinois Basin, coupled with the large number of coal-fired power plants in the region make the basin a prime location for carbon capture storage. This could temper a decline in demand for IB coal if carbon emission legislation is enacted.

Our management is in favor of reasonable and practical steps to protect the environment. We are not in favor of the current cap and trade bill passed by the House and being discussed in the Senate. Unless countries like Mexico, China, India and Russia pass and enforce similar laws, any reduction in carbon omissions in our country would be inconsequential to the ultimate goal.

The POTUS 2011 Budget Proposal

On February 2, 2010, President Obama unveiled his proposed budget for fiscal year 2011 (beginning October 1, 2010). One of the items in the budget that concerns us is the repeal of the percentage depletion allowance for coal companies. Under current tax law we are allowed to deduct 10% of our coal sales as an additional tax deduction. The loss of this deduction would have an adverse effect on our income and cash flows were it to be abolished.

Other

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

Other than the 300 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, fax 303.832.3013 and Sunrise Coal's corporate office is located at 1183 Canvasback Drive, Terre Haute, Indiana 47802, phone 812.299.2800, fax 812.299.2810. Terre Haute is approximately 70 miles west of Indianapolis, Indiana. Our website 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 B bituminous coal.

Our current mine plan indicates 14,200 acres of mineable coal with an approximate 4' to 7' thickness in the project area. Of the 14,200 acres, 12,000 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.

Coal Reserve Estimates

We estimate that, as of December 31, 2009, we had total recoverable reserves of approximately 47.3 million tons consisting of both proven and probable 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. Approximately 36.0 million tons of reserves are classified as proven reserves. “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. The remaining approximately 11.3 million tons of our reserves are classified as probable reserves. “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 (measured) reserves, is high enough to assume continuity between points of observation.

Our reserve estimates were prepared by Samuel Elder, one 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.

The reserve estimate for the 12,000 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. To convert to product tonnage, a 55% mine recovery and an average of 81% washed recovery (coal only recovery, no out-of-seam dilution included) were used.

Example: In-place tonnage x 55% x 81% = 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

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. The majority (95%) of our coal is shipped by rail and the remainder is trucked.

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 without a hoist. 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 is 18' wide with concrete and steel arch construction. All underground mining equipment is powered with electricity and underground compliant diesel.

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.

5.	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.

6.	Quality specifications for salable product are: less than 16% moisture; greater than 11,200 Btu; less than 10% ash; and less than 6.5 LB SO 2 .

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. T here 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. Any inaccuracy in our estimates related to our reserves could result in decreased profitability from lower than expected revenues and/or higher than expected costs.

45% Ownership in Savoy

Savoy operates almost exclusively in Michigan. They have an interest in what is called the Trenton-Black River Play in Southern Michigan. They hold 125,000 gross acres in Hillsdale, Jackson, Lenawee and Washtenaw counties. Savoy drilled about ten wells, six were dry and four were successful, in the play during 2009 and plans ten more for 2010. They operate 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 averages about 195 barrels of oil and 500 thousand cubic feet (Mcf) of gas.

Their proved reserves at December 31, 2009 were 517,000 barrels of oil and 3,317,000 Mcf of gas using prices as dictated by the SEC. The SEC prices are based on the average for the year. Such average oil price is about $20 less than what Savoy is currently receiving. The pre-tax (Savoy is a partnership) present value of their future cash flows discounted at 10% (PV10) was about $14 million. Proved reserves using current prices, with a slight escalation, were 538,000 barrels of oil and 3,600,000 Mcf of gas. The PV10 was about $27 million. About half of their reserves and PV10 are classified as proved undeveloped.

Oil and Gas

We have an ORRI of about 2% on 22,500 acres and a 4% ORRI on 2,500 acres in Laramie County, Wyoming. St. Mary Land & Exploration Company (NYSE:SM) has drilled an apparent discovery well on this acreage. This is a Niobrara oil shale play in the northern D-J Basin. There are 40 additional 640-acre horizontal well locations available for development of this prospect. Assuming no commercial production, the leases will expire in about three years.

ITEM 3. LEGAL PROCEEDINGS. None

ITEM 4. Reserved.

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 OTC Bulletin Board under the symbol “HPCO.OB”. The following table sets forth the high and low sales price for the periods indicated:


2010	High	Low
(January 1 through March 2, 2010)	$ 9.75	$ 7.50
2009
First quarter	3.75	2.95
Second quarter	6.50	3.74
Third quarter	6.75	5.00
Fourth quarter	8.90	6.00
2008
First quarter	4.55	4.00
Second quarter	4.50	3.25
Third quarter	5.50	3.25
Fourth quarter	5.50	2.50

On January 25, 2010, we applied for a NASDAQ Capital Market listing and reserved the trading symbol of HNRG.

During the last two years no dividends were paid. We have no present intention to pay any dividends in the foreseeable future. Our loan agreements restrict our ability to pay dividends.

At March 3, 2010, we had about 463 shareholders of record of our common stock; this number does not include the shareholders holding stock in "street name." The last recorded sales price was $8.30.

Equity Compensation Plan Information as of December 31, 2009

We have 550,000 options outstanding, at an exercise price of $2.30. We also have 1,025,500 restricted stock units that have been granted to certain employees and 899,124 are available for future issuance. Our board of directors approved the plans and collectively they control the company.

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 and recognized an expense of $679,000 in January 2010. Currently we have 434,167 outstanding stock options.

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

We have entered into significant equity transactions with the Yorktown Energy group of partnerships (Yorktown) and other entities that invest with them. Yorktown, our largest shareholder, owns about 55% of our common stock and is represented on our board.

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

Prospective Information

See page 3 of this report for a table that illustrates the status of our current coal contracts.

Liquidity and Capital Resources

We generated $45.2 MM in cash from operations and expect the next two years to be about the same. We do not anticipate any liquidity issues in the foreseeable future. We plan to fund future mine expansion at the Carlisle mine through a combination of draws from the remaining $24 million on our revolver and cash from operations. Our capital expenditures budget for 2010 is in the $22-25 million range. 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.

Results of Operations

The recession has reduced power demand, which reduced the need for coal. During the summer of 2009 stockpiles at some of our customers were high and we were asked by one of our customers to defer a total of 400,000 tons through December 31, 2010. These tons will be shipped in 2011-2013. We agreed to assist our customer because of our valued relationship. With the cold winter and slight pickup in the economy we have not been asked by our customers to defer any more coal.

For 2009, we sold 2,651,000 tons at an average price of $44.30/ton. For 2008, we sold 1,933,000 tons at an average price of $36.39. Our average price for 2010, based on our contracts, will be about $41.50/ton, which is less than the 2009 average price. The lower price for 2010 is due to the mix of our various contracts and corresponding prices.

During, 2008, we sold the substantial remainder of our oil and gas properties at a gain of about $1.8 million. Such sales during 2009 were not material.

Cost of coal sales averaged $24.69/ton in 2009 compared to $20.91 in 2008. The increase was due to inefficiencies during our mine expansion and construction, temporary adverse mining conditions and higher costs associated with government impositions. Our mining employees totaled 309 at December 31, 2009 compared to 230 at December 31, 2008. We expect the cost of coal sales to average $24-25/ton for 2010.

The increase in DD&A was due to the significant increase in our coal sales and the additions to plant and equipment to support the higher sales volume.

SG&A decreased due to a $3 million reduction in compensation connected with our restricted stock plans offset primarily by higher costs due to our significantly higher level of operations. Based on the number of RSUs we have outstanding at December 31, 2009, our stock based compensation amortization expense for the next four years will be $6.9 million: $1.9 million for 2010; $1.8 million for 2011; $1.7 million for 2012 and $1.5 million for 2013. Our SG&A expense for 2009 plus the amortization of our RSUs is representative of our future SG&A expense.

Included in 2009 interest expense was a credit of $886,000 relating to our interest rate swaps; such amount for 2008 was a charge of $1,109,000 In addition, we capitalized $293,000 in interest expense for 2009 compared to $176,000 for 2008. Because our mine expansion was completed in the summer of 2009, we are no longer capitalizing interest.

For 2008, the $2.3 million equity loss from Savoy resulted primarily from Savoy taking a $2.6 million impairment charge relating to their oil and gas properties. Furthermore, the difference between the purchase price and our pro rata share of Savoy's partners' capital was amortized based on Savoy's units-of-production rate and amounted to about $333,000 for 2008. In addition, due to deteriorating industry conditions, we took a $1.4 million impairment charge relating to our investment in Savoy. Considering this impairment charge, we no longer have a difference between the purchase price and our pro rata share of Savoy's partners' capital. For 2009 Savoy took an impairment charge for their undeveloped acreage of $1.8 million. We expect Savoy to show a smaller loss for 2010 compared to 2009 assuming current oil and gas prices remain relatively the same throughout the year

At December 31, 2009, we have federal net operating loss carry forwards of about $2.4 million and expect to utilize them in 2010. For 2009, we had pretax income after noncontrolling interest of about $34 million and a tax provision of about $13.8 million (an effective tax rate of 40.6%). We expect these income trends and tax rates to continue for the foreseeable future.

Critical Accounting Estimate and Significant Accounting Policies

We believe that the estimate of our coal reserves is our only critical accounting estimate. 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 would be affected. Furthermore, if the reserves are materially overstated our liquidity and stock price could be adversely affected.

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.

Climate Change

This topic was previously discussed on page 9 of this report.

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	21

Consolidated Balance Sheet	22

Consolidated Statement of Operations	23

Consolidated Statement of Cash Flows	24

Consolidated Statement of Stockholders' Equity	25

Notes to Consolidated Financial Statements	26

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 sheets of Hallador Energy Company and Subsidiaries as of December 31, 2008 and 2009, 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, 2009. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated 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 consolidated 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 consolidated financial statements. An audit also includes 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, 2008 and 2009, and the results of their operations and their cash flows for each of the years in the two year period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.

/s/ Ehrhardt Keefe Steiner & Hottman PC

March 4, 2010

Denver, Colorado

Consolidated Balance Sheet

As of December 31,

( in thousands, except per share data )

ASSETS
Current assets:		2009		2008
Cash and cash equivalents	$	15,226	$	21,013
Certificates of deposit		3,458
Prepaid Federal income taxes		1,511		1,531
Accounts receivable		5,411		6,113
Coal inventory		2,165		776
Other		2,498		1,928
Total current assets		30,269		31,361

Coal properties, at cost:
Land, buildings and equipment		95,270		55,027
Mine development		47,479		45,289
		142,749		100,316
Less - accumulated DD&A		(16,958	)	(7,233	)
		125,791		93,083
Investment in Savoy		6,259		7,911
Other assets		2,771		3,710
	$	165,090	$	136,065
LIABILITIES AND EQUITY
Current liabilities:
Current portion of bank debt	$	10,000	$	2,500
Accounts payable and accrued liabilities		9,950		11,563
State income tax payable		464		605
Other		179		310
Total current liabilities		20,593		14,978

Long-term liabilities:
Bank debt, net of current portion		27,500		37,500
Interest rate swaps, at estimated fair value		1,404		2,290
Deferred income taxes		1,699		1,700
Asset retirement obligations		922		686
Other		4,345		4,345
Total long-term liabilities		35,870		46,521
Total liabilities		56,463		61,499
Equity:
Hallador stockholders’ equity:
Preferred stock, $.10 par value, 10,000 shares authorized; none issued
Common stock, $.01 par value, 100,000 shares authorized; 27,782 and 22,446 outstanding, respectively		277		224
Additional paid-in capital		85,245		69,739
Retained earnings		23,105		2,920
Total Hallador stockholders' equity		108,627		72,883
Noncontrolling interest				1,683
Total equity		108,627		74,566
	$	165,090	$	136,065

See accompanying notes.

Consolidated Statement of Operations

For the years ended December 31,

( in thousands, except per share data )

	2009			2008

Revenue:
Coal sales	$	117,445		$	70,337
Equity loss - Savoy		(1,652	)		(2,320	)
Other		541			2,181
		116,334			70,198
Costs and expenses:
Cost of coal sales		65,442			40,413
DD&A		8,837			4,630
SG&A		4,038			6,128
Interest (1)		2,040			4,029
Impairment - Savoy					1,396
		80,357			56,596

Income before income taxes		35,977			13,602

Less income taxes:
Current		728			1,226
Deferred		13,044			1,700
		13,772			2,926

Net income		22,205			10,676

Less net income attributable to the noncontrolling interest		(2,020	)		(1,776	)

Net income attributable to Hallador	$	20,185		$	8,900


Net income per share attributable to Hallador:
Basic	$	.84		$	.47
Diluted	$	.83		$	.46

Weighted average shares outstanding:
Basic		24,017			18,980
Diluted		24,441			19,286

(1)	Included in interest expense for 2009 is a credit of $886 and for 2008 a charge of $1,109 for the change in the estimated fair value of our interest rate swaps. We also capitalized $ 293 and $ 176 in interest charges for 2009 and 2008, respectively.

See accompanying notes.

Consolidated Statement of Cash Flows

For the years ended December 31,

( in thousands )

	2009			2008
Operating activities:
Net income including noncontrolling interests	$	22,205		$	10,676
Deferred income taxes		13,044			1,700
Equity loss – Savoy		1,652			2,320
Impairment – Savoy					1,396
Gain on sale of oil and gas properties					(1,822	)
DD&A		8,837			4,630
Change in fair value of interest rate swaps		(886	)		1,109
Stock-based compensation		534			2,826
Other		379			133
Change in current assets and liabilities:
Accounts receivable		900			(3,707	)
Coal inventory		(1,389	)		(684	)
Income taxes		(141	)		(925	)
Accounts payable and accrued liabilities		795			2,484
Other		(710	)		(1,384	)
Cash provided by operating activities		45,220			18,752
Investing activities:
Acquisition of additional 20% interest in Sunrise*					(11,772	)
Capital expenditures for coal properties		(43,491	)		(21,898	)
Other		(3,171	)		2,676
Cash used in investing activities		(46,662	)		(30,994)
Financing activities:
Proceeds from bank debt		4,000			42,000
Payments of bank debt		(6,500	)		(37,357	)
Proceeds from stock sales		24,900			21,984
Acquisition of remaining 20% interest in Sunrise*		(25,805	)
Cash distributions to noncontrolling interests		(909	)
Other		(31	)		(350	)
Cash (used in) provided by financing activities		(4,345	)		26,277
Increase (decrease) in cash and cash equivalents		(5,787	)		14,035
Cash and cash equivalents, beginning of year		21,013			6,978
Cash and cash equivalents, end of year	$	15,226		$	21,013

Cash paid for interest (net of amount capitalized - $293 and $176)	$	3,307		$	2,879
Cash paid for income taxes	$	850		$	2,000
Changes in accounts payable for coal properties	$	(1,810	)	$	3,032
Non cash portion of Sunrise buyout	$	6,800

*The 2008 acquisition was treated as an investing activity and accounted for under purchase accounting rules: however, due to changes in accounting rules, the 2009 acquisition was treated as a financing activity and accounted for as an equity transaction.

See accompanying notes.

Consolidated Statement of Stockholders’ Equity

( in thousands )

	Shares		Common Stock		Additional Paid-in Capital			Retained Earnings			Total
Balance January 1, 2008		16,363	$	163	$	44,990		$	(5,980	)	$	39,173

July stock sale, net of issuance costs		5,500		55		21,929						21,984

Restricted shares issued		583		6		2,280						2,286

Stock-based compensation						540						540

Net income attributable to Hallador									8,900			8,900

Balance December 31, 2008		22,446		224		69,739			2,920			72,883

Equity offering		4,150		42		24,858						24,900

Stock issued to Sunrise members for their remaining 20% interest valued at par (fair value of $6,800); See Note 4.		1,133		11		(11	)

Cash ($25,805) paid to Sunrise members for their remaining 20% interest, net of deferred income tax assets of $13,045 and $3,703 to close out the noncontrolling interest (treated as an equity transaction) and a $909 cash distribution to the noncontrolling interests						(9,966	)					(9,966	))

Restricted shares issued		29				161						161

Stock-based compensation						292						292

Bonus shares for employees		24				181						181

Other						(9	)					(9	)

Net income attributable to Hallador									20,185			20,185

Balance December 31, 2009		27,782	$	277	$	85,245		$	23,105		$	108,627

See accompanying notes.

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 a shallow underground mine located in western Indiana. We also own a 45% equity interest in Savoy Energy L.P., a private oil and gas company which has operations in Michigan.

We have entered into significant equity transactions with Yorktown and other entities that invest with Yorktown. Yorktown currently owns about 55% of our common stock and represents one of the seven seats on our board.

Reclassification

To maintain consistency and comparability, certain amounts in the 2008 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. 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 - 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 discounted 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, as granted by state authorities, for revisions to the estimated reclamation costs, and for revisions to the timing of those costs.

The following table reflects the changes to our ARO:

		2009		2008

Balance beginning of period	$	686	$	646
Accretion		58		40
Change in cost estimate		178
Balance end of period	$	922	$	686

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 is 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, stock awards, and restricted stock awards.

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.

Revenue Recognition

We recognize revenue from coal sales at the time risk of loss passes to the customer at contracted amounts.

Long-term Contracts

As of December 31, 2009, we are committed to supply to three customers about 13 million tons of coal during the next five years. These contracts represent about 27% of our recoverable reserves. During 2009 and 2008, three of our customers accounted for over 90% of our sales: for 2009 one customer accounted for 62%, the second for 18%, and the third for 17%; for 2008 one accounted for 43%, the second for 31%, 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.

Recently Adopted Accounting Guidance

On January 1, 2009, we adopted the authoritative guidance issued by the FASB that changed the accounting and reporting for noncontrolling interests. Noncontrolling interests are reported as a component of equity separate from the parent’s equity, and purchases or sales of equity interests that do not result in a change in control are to be accounted for as equity transactions. In addition, income attributable to a noncontrolling interest is to be included in net income and, upon a loss of control, the interest sold, as well as any interest retained, is to be recorded at fair value with any gain or loss recognized in net income.

New Accounting Pronouncements

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

(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:

	2009		2008
Expected amount	$	11,885	$	4,021
State income taxes, net of federal benefit		1,784		573
Change in valuation allowance				(1,257	)
Other		103		(411	)
	$	13,772	$	2,926

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

	2009			2008
Long-term deferred tax assets:
Federal NOL carry forwards	$	921		$	945
AMT credit carry forwards		1,008			690
Stock-based compensation		605			1,291
Investment in Savoy		2,134			2,153
Other		1,014			1,061
Net long-term deferred tax assets		5,682			6,140
Long-term deferred tax liabilities:
Coal properties		(7,381	)		(7,840	)
Net deferred tax liability	$	1,699		$	1,700

For accounting purposes the Sunrise buyout (see Note 4) 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 equity.

At December 31, 2009, we have federal net operating loss carry forwards of about $2.4 million and expect to utilize them in 2010. We also have percentage depletion carry forwards of about $1.2 million which have no expiration date and AMT credit carry forwards of about $1 million.

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 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.

(3) Common Stock, Restricted Stock and Stock Options

Common Stock

In September 2009, in a private placement transaction, we sold 4,150,000 shares of our common stock for an aggregate cash purchase price of $24.9 million ($6/share). The proceeds from the sale were used to purchase the remaining 20% membership interests in Sunrise. All but 450,000 shares were sold to our existing shareholders and board members. Yorktown Energy Partners VIII, LP, a private partnership affiliated with board member Bryan Lawrence, purchased 2,950,000 shares and an entity affiliated with board member Sheldon Lubar purchased 750,000 shares.

On July 21, 2008, we sold 5.5 million shares of our common stock for $22 million ($4 per share) in a private placement transaction to existing shareholders.

Restricted Stock Grants – 2009

On September 14, 2009 our board authorized the issuance of up to 1,000,000 additional restricted stock units (RSUs). At a meeting of our compensation committee held in December 2009, 330,000 RSUs were granted to Victor Stabio, our CEO; 250,000 were granted to Brent Bilsland our president and 200,000 were granted to W. A. Bishop, our CFO. The RSUs will vest equally over four years. The closing price of our stock on the date of grant was $7.90. During 2009 we also issued to other employees 95,000 RSUs which vest after three years of employment.

Stock based compensation expense for 2009 was $353,000. For 2010 based on existing RSUs outstanding, stock based compensation expense will be about $1.9 million.

As of December 31, 2009, we have about 899,000 RSUs available for future issuance and there are 1,025,500 RSUs outstanding which have not vested and have a value of about $8 million based on a year-end closing price of $7.85 per share.

Restricted Stock Grants - 2008

Effective April 8, 2008, the Board approved the 2008 Restricted Stock Unit Plan. On July 7, 2008 the plan was amended to increase the authorized issuance of RSUs from 450,000 units to 1,350,000 units. Vesting occurs at the end of three years of employment. Upon vesting, each RSU entitles the recipient to receive one share of common stock. If the RSU recipient’s employment with us ceases for any reason prior to vesting, the RSUs will be cancelled and the recipient will no longer have any right to receive any shares of common stock. Due to employee resignations 15,000 RSUs were forfeited back to the plan.

On May 6, 2008, we awarded 185,000 RSUs which vest on April 1, 2011. The RSUs were valued at $4.25 per share based on the closing price on that date. On May 14, 2008, we accelerated vesting on 50,000 shares and recognized an expense of about $212,000.

On July 7, 2008, we awarded 820,000 RSUs, all of which vest on July 7, 2011. Of the 820,000 RSUs awarded, Victor P. Stabio, our CEO received 450,000 units and Brent Bilsland, our President, received 300,000 units. These RSUs were valued at $3.55 per share based on the closing price on that date. During October 2008, we accelerated vesting on 815,000 RSUs, of which 450,000 were issued to Victor Stabio and 300,000 were issued to Brent Bilsland, and the remaining 65,000 were issued to others. Our stock was selling in the $2.75 to $2.85 range on the dates of acceleration. During the fourth quarter 2008, we recognized an expense of about $2.9 million for these RSUs.

Total amortization expense for 2008 was about $3.6 million relating to our RSUs.

Stock Grant to Employees

In December 2009 we distributed 24,000 shares of our common stock to all of our hourly mine employees as an incentive bonus and recorded a charge of $181,000 based on the stock price that day.

Stock Options

In April 2005, we granted 750,000 options at an exercise price of $2.30. These options fully vested in April 2008 and expire in April 2015. No options were exercised during 2009 and 2008. At December 31, 2009 and 2008, we had 550,000 outstanding stock options.

Subsequent Event

(4) Sunrise Coal Acquisition

Through a series of independent transactions which began in 2006 and ended in September 2009, we now own 100% of Sunrise Coal, LLC (Sunrise). At the end of 2006 and 2007 we owned 60% of Sunrise; at the end of 2008 we owned 80%; and at the end of 2009 we owned 100%. In July 2008 we purchased an additional 20% interest in Sunrise for about $12 million bringing our ownership to 80% as of December 31, 2008. The $12 million was allocated to mine development costs.

Purchase of Remaining Interest in Sunrise

On September 16, 2009, we entered into agreements to purchase the remaining 20% membership interest in Sunrise Coal, LLC (“Sunrise”), from the existing members for an aggregate purchase price of about $32.6 million, consisting of about $25.8 million in cash and 1,133,328 in shares of our common stock valued at $6/share ($6.8 million). Brent Bilsland, our new president and board member, received cash of about $3.185 million and 8,333 shares of our stock for his approximate 2% interest and his spouse received cash of about $1.775 million and 208,333 shares of our stock for her interest (slightly less than 2%). His parents also sold their approximate 8% interest in Sunrise under the same terms receiving 383,332 shares and the remainder in cash. In addition, simultaneously Brent Bilsland purchased for cash 200,000 shares (at $6/share) directly from Victor Stabio, our CEO.

(5) 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, 2009, we owe $37.5 million on the term loan. We have outstanding letters of credit in the amount of $6 million, which leaves about $24 million available under the revolver. We pay a 2.5% fee on the letters of credit and a .5% commitment fee on the unused funds. Substantially all of Sunrise's assets are pledged under this loan agreement and we are the guarantor. Debt maturities are as follows: 2010 - $10 million; 2011 - $10 million; and 2012 - $17.5 million. The loan agreement requires customary covenants, required financial ratios and restrictions on dividends or distributions. Closing costs on this loan agreement were about $1.2 million and are being amortized using the effective interest method over its term. The current interest rate is LIBOR (0.24%) plus 2.50% or 2.74%.

In connection with the old loan agreements, we entered into two agreements swapping variable rates for fixed rates. The first swap agreement, which initially covered $26 million in debt, commenced on July 15, 2007 and matures on July 15, 2012; the current notional amount is about $15 million. The second swap agreement, which initially covered $10 million, commenced on December 28, 2007 and matures on December 28, 2011; the current notional amount is about $8 million. Considering the two swap agreements, our current interest rate is about 5.7%. At December 31, 2009, 2008 and 2007, our interest rates swaps resulted in a liability of $1.4 million, $2.3 million and $1.2 million, respectively. The difference of $900,000 is included as a reduction in our interest expense for the year ended December 31, 2009 and the difference of $1.1 million was included as additional interest expense for 2008.

Accounting rules require us to recognize all derivatives on the balance sheet at estimated fair value. Derivatives that are not hedges must be adjusted to estimated fair value through earnings. We have no derivatives designated as a hedge. The recorded value of our bank debt approximates fair value as it bears interest at a floating rate.

(6) 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. We account for our interest in Savoy using the equity method of accounting.

Below (in thousands) is a condensed balance sheet at December 31, for both years and a condensed statement of operations for both years.

Condensed Balance Sheet

(unaudited)


	2009	2008
Current assets	$ 7,764	$ 10,639
Oil and gas properties, net	12,114	12,021
	19,878	22,660

Total liabilities	5,987	5,120
Partners' capital	13,891	17,540
	$ 19,878	$ 22,660

Condensed Statement of Operations

(unaudited)


	2009	2008
Revenue	$ 7,754	$ 8,340
Expenses	(11,403)	(12,747)
Net loss	$ (3,649)	$ (4,407)

For 2008, the $2.3 million equity loss from Savoy resulted primarily from Savoy taking a $2.6 million impairment charge relating to their oil and gas properties. Furthermore, the difference between the purchase price and our pro rata share of Savoy's partners' capital was amortized based on Savoy's units-of-production rate and amounted to about $333,000 for 2008. In addition during 2008, due to deteriorating industry conditions, we took a $1.4 million impairment charge relating to our investment in Savoy. Considering this impairment charge, we no longer have a difference between the purchase price and our pro rata share of Savoy's partners' capital. For 2009 Savoy took an impairment charge for their undeveloped acreage of $1.8 million. We expect Savoy to show a smaller loss for 2010 compared to 2009 assuming current oil and gas prices remain relatively the same throughout the year

Unaudited

Our 45% equity interest in Savoy's proved reserves at December 31, 2009 were 232,000 barrels of oil and 1,493,000 Mcf of gas. Our 45% equity interest in Savoy's standardized measure of discounted future net cash flows (pre tax since Savoy is an LLP) at December 31, 2009 was about $6.3 million.

(7) Sale of Oil and Gas Properties

In October 2008, we sold unproved properties for about $2 million and recognized a gain of about $1.4 million. Other sales during 2008 resulted in gains of about $400,000.

(8) Employee Benefits

We have no defined benefit pension plans or any post-retirement benefit plans. Our mine employees participate in a 401(k) Plan, where we match 100% of the first 3% 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. Our 2009 costs for the 401(k) matching were about $283,000 and our costs for health benefits were about $1.8 million. Our 2008 costs for the 401(k) matching were about $190,000 and our costs for health benefits were about $822,000. The 2009 amortized costs for the Deferred Bonus Plan were about $90,000. The 2008 costs were not material as the plan was implemented in December 2008. The costs for the production bonus plan were $324,000 in 2009 and $490,000 in 2008.

Our mine employees are also covered by workers compensation and such costs for 2009 and 2008 were about $1.9 million and $1.7 million, respectively. Workers’ compensation is a no-fault system by which individuals who sustain work related injuries or occupational diseases are compensated. Benefits and coverages 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 $2 million which is our aggregate deductible. Based on discussions and representations from our insurance carrier we currently have no basis to record any liability pertaining to workers’ compensation benefits. We have a safety conscious work force and our worker’s compensation injuries have been minimal. Our mine has been in operation for about three years.

(9) Fair Value Measurements

We account for certain assets and liabilities at fair value. The hierarchy below lists three levels of fair value based on the extent to which inputs used in measuring fair value are observable in the market. We categorize each of our fair value measurements in one of these three levels based on the lowest level input that is significant to the fair value measurement in its entirety. These levels are:


		Level 1:		Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. We have no Level 1 instruments.

		Level 2:		Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. We have no Level 2 instruments.

		Level 3:		Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). Our Level 3 instruments are comprised of interest rate swaps. Although we utilize third party broker quotes to assess the reasonableness of our prices and valuation, we do not have sufficient corroborating market evidence to support classifying these liabilities as Level 2.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

Not applicable .

ITEM 9A(T). 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, 2009.

There has been no change in our internal control over financial reporting during the quarter ended December 31, 2009 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 EKS&H pursuant to temporary rules of the SEC that permits us to provide only our report in this annual report.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

Directors

DAVID HARDIE, 59, is the Chairman of the Board and has served as a director since July 1989. He is the President of Hallador Investment Advisors Inc., which manages Hallador Equity Fund, Hallador Fixed Income Fund, Hallador Alternative Assets Fund and Hallador Balance Fund; he also is a General Partner of Hallador Venture Partners LLC, the General Partner of Hallador Venture Fund II & III. Mr. Hardie is and serves as a director and partner of other private entities that are owned by members of his family and is also a director of Sunrise Coal, LLC. Mr. Hardie is a graduate of California Polytechnic University, San Luis Obispo. He also attended the Owner/President Management program offered by Harvard Business School.

STEVEN HARDIE, 56, has been a director since 1994. He and David Hardie are brothers. For the last 24 years he has been a private investor. He is the Vice- President of Hallador Investment Advisors, which manages Hallador Equity Fund, Hallador Fixed Income Fund, Hallador Alternative Assets Fund and Hallador Balance Fund. He also serves as a director and partner of other private entities that are owned by members of his family.

BRYAN H. LAWRENCE, 67, has been one of our directors since November 1995. He is a founder and senior manager of Yorktown Partners LLC which manages investment partnerships formerly affiliated with Dillon, Read & Co. Inc., an investment-banking firm (Dillon, Read). He had been employed with Dillon, Read since 1966, serving most recently as a Managing Director until the merger of Dillon, Read with SBC Warburg in September 1997. He also serves as a Director of Approach Resources, Inc., Star Gas Partners, L.P., Crosstex Energy, Inc. and Crosstex Energy, L.P. (each a United States public company), Winstar Resources Ltd. (a Canadian Public Company) and certain non-public companies in the energy industry in which Yorktown partnership holds equity interests, one of which is Sunrise Coal, LLC. Mr. Lawrence is a graduate of Hamilton College and has a MBA from Columbia University.

SHELDON B. LUBAR, 80, was appointed to our board in July 2008. Since 1977, Mr. Lubar has been Chairman of the Board of Lubar & Co. Incorporated, a private investment and management firm he founded. During the past five years he served on the board of, Weatherford International, Inc., Grant Prideco, Inc., C2, Inc. and Total Logistics, Inc. Mr. Lubar currently serves on the board of Crosstex Energy, Inc., Crosstex Energy L.P., Star Gas Partners L.P. and Approach Resources, Inc. Mr. Lubar holds a bachelor's degree in Business Administration and a law degree from the University of Wisconsin-Madison. He was awarded an honorary Doctor of Commercial Science degree from the University of Wisconsin-Milwaukee in 1988, and an honorary Doctor of Humanities degree from the University of Wisconsin-Madison in 2009.

JOHN VAN HEUVELEN, 63, was appointed to our board in September 2009 and has been a member of the board of directors of MasTec, Inc. (NYSE:MTZ) since June 2002 and currently serves on their audit committee. He was chairman of their audit committee and the financial expert from 2004 to 2009. He also served on the board of directors of LifeVantage, Inc. (OTC:LFVN) from August 2005 through August 2007. From 1999 to the present, Mr. Van Heuvelen has been a private equity investor based in Denver, Colorado. His investment activities have included private telecom and technology firms, where he still remains active. Mr. Van Heuvelen spent 14 years with Morgan Stanley and Dean Witter Reynolds in various executive positions in the mutual fund, unit investment trust and municipal bond divisions before serving as president of Morgan Stanley Dean Witter Trust Company from 1993 until 1999.

VICTOR P. STABIO, 62, is our CEO and a director. He joined us in March 1991 as our President and CEO and has been active in the oil and gas business for the past 32 years. Mr. Stabio is a director of Sunrise Coal, LLC and also a director of Savoy Exploration, the general partner of Savoy Energy, LP.

BRENT K. BILSLAND, 36, was named our President and appointed to our board in September 2009. He has been President and a director of Sunrise Coal, LLC since July 31, 2006. Previously, Mr. Bilsland was Vice President of Knapper Corporation; a family owned farming business from 1998 to 2004. Mr. Bilsland is a graduate of Butler University located in Indianapolis, Indiana.

The SEC recently passed new rules that require us to disclose why we think our directors are qualified to be on our board. Below are the reasons we think our board members are qualified to serve.

Messrs. David and Steven Hardie have served as our board members for the last 20 and 16 years, respectively. Both have been private investors in many companies over their careers and served on numerous boards. At one time the two brothers and their family owned over 50% of our stock. Currently David and Steven Hardie beneficially own through various entities about 15% of our stock with a value of about $30 million, based on current prices, giving them a vested interest in monitoring the well being of our company. David Hardie has a pecuniary interest in only 834,624 shares, or 3% of our issued and outstanding shares, held by the entities described in the footnote to the beneficial ownership tables listed in Item 12. David Hardie disclaims any beneficial ownership in any other shares held by such entities.

Mr. Lawrence, who controls about 55% of our stock, has been a board member for the last 14 years. He sits on numerous boards for both private and public companies that are involved in the energy business. As most of our other board members, he too has a significant indirect monetary investment in our company and accordingly has a vested interest in our success.

Mr. Lubar who owns about 10% of our stock has been on our board for about two years. Mr. Lubar is a very successful entrepreneur and sits on numerous boards in the energy business along with Mr. Lawrence. With his 10% stake, he too has a vested interest in our success.

Messrs. Stabio and Bilsland are our CEO and President, respectively. For smaller companies like ours it is common practice for the CEO and President to serve on the board. They too have significant personal investments in the company. Mr. Stabio owns about 2% of our stock and Mr. Bilsland and his family owns about 4%. Messrs. Stabio and Bilsland also, respectively, have 330,000 and 250,000 RSUs that will vest equally over 4 years.

Mr. Van Heuvelen was appointed to our board in September 2009. He currently serves on the audit committee of a NYSE company and has been on such board for the last eight years. Previously he was an officer with Dean Witter in their NYC headquarters. Early in his career he was actively involved in the energy business while living in Montana. Mr. Van Heuvelen’s contacts with investment banking firms will prove invaluable to us as we attempt to grow the company.

We believe that board members who are willing and able to have a sizable portion, or in some case a substantial portion, of their personal net worth invested in our company tend to be conscientious directors. In other words, our directors’ interests are closely aligned with our shareholders’ interests. If our stock goes up, our directors’ win and so do our other shareholders. Furthermore, we have no D&O insurance and only one of our seven directors receive directors’ fees.

Executive Officers

W. ANDERSON BISHOP, CPA, 56, was named our CFO and Chief Accounting Officer in September 2009. He was our CFO and a board member during 1990-1993. From 1975 through 1990 he was with Price Waterhouse, predecessor to PricewaterhouseCoopers, in their Oklahoma City and Denver offices. Mr. Bishop graduated from the University of Oklahoma. For the past 16 years he was the Executive Vice President, CFO and 1/3 owner of the SEC Institute Inc., a private company in the business of training employees of private and public companies in the filing and reporting requirements of the U.S. Securities and Exchange Commission. During those 16 years he also assisted us in preparing our SEC filings. In July 2009 he sold his interest in such company and is no longer involved with the SEC Institute. He also served on the audit committee of SemGroup Energy Partners, L.P., now called Blueknight Energy Partners, L.P. (OTCPK:BKEP) from July 2007 through July 2008.

LAWRENCE D. MARTIN, CPA, 44, was appointed Chief Financial Officer of Sunrise Coal, LLC on January 29, 2008. Prior to his employment with Sunrise in October 2008, he worked 19 years for Clifton Gunderson (12th largest U.S. Public Accounting Firm) from January 1989 to October 2008. Mr. Martin was a Senior Manager in Tax for the previous 6 years and an Audit Senior Manager for the 5 preceding years. Mr. Martin is a graduate from Indiana State University and has his Bachelor of Science in Accounting. He received his C.P.A in 1991.

Section 16(a) Beneficial Ownership Reporting Compliance

Messrs. Stabio, Bilsland and Bishop were all a few days late in the filing of Form 4s to report their receipt of RSUs granted in December 2009.

Our Code of Ethics is filed as Exhibit 14 to this Form 10-K.

Audit Committee Report

Our audit committee oversees our financial reporting process on behalf of the board of directors. Management has the primary responsibility for the financial statements and the reporting process including the systems of internal controls.

In fulfilling its oversight responsibilities, the audit committee reviewed and discussed with management the audited financial statements contained in this Form 10-K.

Our independent registered public accounting firm, EKS&H, is responsible for expressing an opinion on the conformity of the audited financial statements with accounting principles generally accepted in the United States of America. The audit committee reviewed with EKS&H the firm's judgment as to the quality, not just the acceptability, of our accounting principles and such other matters as are required to be discussed with the audit committee under generally accepted auditing standards.

The audit committee discussed with EKS&H the matters required to be discussed by SAS 61 (Codification of Statement on Auditing Standards, AU § 380), as may be modified or supplemented. The committee received written disclosures and the letter from EKS&H required by applicable requirements of the Public Company Accounting Oversight Board regarding EKS&H’s communications with the audit committee concerning independence, and has discussed with EKS&H its independence.

Based on the reviews and discussions referred to above, the audit committee recommended to the board of directors that the audited financial statements be included in the Form 10-K for the year ended December 31, 2009 for filing with the SEC.

John Van Heuvelen

David Hardie

Sheldon Lubar

ITEM 11. EXECUTIVE COMPENSATION

Name and Principal Position	Year	Salary	Bonus	Stock Awards (1)	All Other Compensation (2)	Total

Victor P. Stabio CEO	2009 2008	$180,000 180,000	$25,846 90,000	$2,607,000 1,597,500		$2,812,846 1,867,500
Brent Bilsland President	2009 2008	157,470 96,000	13,333 34,000	1,975,000 1,065,000	$5,124 3,000	2,150,927 1,198,000
W. Anderson Bishop CFO (3)	2009	25,000	5,900	1,580,000		1,610,900

----------------------------
(1) Based on grant date fair value.

(2) Represents company contributions to the 401(k) plan.

(3) Mr. Bishop began employment in October 2009.

None of our executive officers have employment agreements nor do they have any retirement benefits.

There are no “change in control” agreements other than unvested RSUs would vest and unexercised options would be monetized.

No options were granted or exercised during 2009 and 2008.

Outstanding Equity Awards at Fiscal Year-End

Other than Mr. Stabio, none of our executive officers have stock options. At December 31, 2009, Mr. Stabio's in-the-money value of his exercisable options (200,000 with a $2.30 exercise price) was about $1,110,000 and expire on April 15, 2015.

The three officers above were each granted RSUs in December 2009. Mr. Stabio was granted 330,000; Mr. Bilsland was granted 250,000 and Mr. Bishop was granted 200,000. The RSUs vest equally over four years. Our stock closed at $7.85 at the end of 2009. The market value of these RSUs at the end of 2009 was: Mr. Stabio- $2.6 million; Mr. Bilsland- $2 million and Mr. Bishop- $1.6 million. They have no other outstanding equity awards.

Salary increases for 2010

Effective January 1, 2010 Mr. Stabio's annual salary was increased from $180,000 to $195,000 per year and Mr. Bishop’s salary was increased from $100,000 to $130,000. Mr. Bilsland's salary was increased from $160,000 to $175,000 effective April 1, 2010. We have no written employment agreements with any of our officers. Bonuses, if any, are paid on a discretionary basis.

Compensation of Directors

Other than Mr. Van Heuvelen, our outside directors receive no compensation for their services. Mr. Van Huevelen is paid $100,000 per year. He has the option to be paid in cash or shares of our stock. For 2009 he elected to be paid in stock.

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

This table shows the number and percentage of common shares owned for each shareholder known by us to beneficially own 5% or more of our stock.

Name	No. Shares (1)	% of Class (2)

Hardie Family Shares (3)	4,295,544	15.46
555 Dale Drive Incline Village, NV 89451
Yorktown Energy Partners (4)	15,207,256	54.73
410 Park Avenue, 19 th Floor New York, NY 10022.

Lubar Equity Fund LLC 700 North Water Street Suite 1200 Milwaukee, WI 53202	2,788,685	10.04

(1)	This information is based on information as of March 3, 2010 furnished by each shareholder or contained in filings made by the shareholder with Securities and Exchange Commission.
(2)	The percentages of ownership are calculated based on a total of 27,782,028 common shares issued and outstanding as of March 3, 2010.
(3)	Hallador Alternative Assets Fund LLC (“HAAF”) beneficially owns 3,174,188 shares. Robert C. Hardie L.P. beneficially owns 823,041 shares. Hallador, Inc. owns 273,315 shares. Sandra Hardie, wife of Steven Hardie owns 25,000 shares. Mr. David Hardie, by reason of being Managing Member of HAAF may be deemed to beneficially own 3,174,188 shares of our stock. Additionally, David Hardie is an executive officer of Browns Valley, Inc., which is deemed to directly or indirectly control the holdings of Robert C. Hardie, L.P., as its General Partner which equal 823,041 shares of our stock. Further, as a director of Hallador, Inc., David Hardie may be deemed to directly or indirectly control its holdings, or 298,315 shares of our stock. David Hardie has a pecuniary interest in 834,624 shares, or 3% of our issued and outstanding shares, held by the entities above. David Hardie disclaims any beneficial ownership in any other shares held by the entities. Mr. Steven Hardie, by reason of being Managing Member of HAAF may be deemed to beneficially own such 3,174,188 shares of our stock. Additionally, as a director of Hallador, Inc., Steven Hardie may be deemed to directly or indirectly control its holdings, or 298,315 shares of our stock.
(4)	Includes 6,557,166 shares owned by Yorktown Energy Partners, VI L.P., 5,700,090 shares owned by Yorktown Energy Partners, VII L.P., and 2,950,000 shares owned by Yorktown Energy Partners VIII, L.P.

The table below shows the number and percentage of common shares beneficially owned by each of our directors and officers and by group at March 3, 2010. Beneficial ownership of certain shares has been, or is being, specifically disclaimed by certain directors in ownership reports filed with the SEC.

Name	No. Shares	% of Class ( 1)

David Hardie and Steven Hardie (2)	4,295,544	15.46

Bryan H. Lawrence (3)	15,257,256	54.91

Sheldon Lubar (4)	2,788,685	10.04

John Van Heuvelen	36,667	0.13

Victor P. Stabio (5)	730,473	2.61

Brent K. Bilsland (6)	781,666	2.81

W. Anderson Bishop	58,500	0.21

All directors and executive officers as a group (9)	23,977,791	86.29

(1)	The percentages of ownership are calculated based on a total of 27,782,028 common shares outstanding.
(2)	See footnote 3 in the table for shareholders' owning more than 5%.
(3)	Mr. Lawrence’s address is 410 Park Avenue, 19 th Floor, New York, NY 10022. Mr. Lawrence owns 50,000 shares directly. The remainder is held by Yorktown Energy Partners VI, L.P., Yorktown Energy Partners VII, L.P., and Yorktown Energy Partners, VIII L. P., each affiliated with Mr. Lawrence.
(4)	Includes shares owned by Lubar Equity Fund LLC.
(5)	Includes 530,743 shares held in trust and 200,000 options exercisable within 60 days.
(6)	Includes 208,833 shares owned by Alexa Bilsland, Mr. Bilsland’s wife.

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

Our Audit Committee consists of Mr. Van Heuvelen, Chairman, Mr. David Hardie and Mr. Lubar. Our Compensation Committee consists of Mr. David Hardie, Chairman, Mr. Lawrence and Mr. Lubar. We have no nominating committee.

Mr. Van Heuvelen serves as our audit committee financial expert.

We had six board meetings and four audit committee meetings during 2009 and all members attended at least 95% of the meetings.

We have entered into significant equity transactions with Yorktown and other entities that invest with Yorktown. Yorktown, our largest shareholder, owns about 55% of our common stock and represents one of the seven seats on our board.

In February 2009 in connection with a verbal relocation plan, we purchased from Mr. Martin his personal residence, which is about 50 miles from the office, for about $185,000. Mr. Martin moved to his new residence in August near the Terre Haute office. We plan to sell the house this summer.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

The audit fees incurred for 2009 and 2008 were $148,000 and $141,500, respectively. Our auditors only perform audit services for us.

Pre-approval Policy

In 2003 the Audit Committee adopted a formal policy concerning approval of audit and non-audit services to be provided by EKSH. The policy requires that all services EKSH provides to us be pre-approved by the Committee. The Committee approved all services provided by EKSH during 2009 and 2008.

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 Purchase and Yorktown Energy Partners II, L.P., as Seller relating to the purchase and sale of limited partnership interests in Savoy Energy Limited Partnership (3)
10.2	Letter of Intent dated January 5, 2006 between Hallador Petroleum Company and Sunrise Coal, LLC (4)
10.3	Subscription Agreement - by and between Hallador Petroleum Company and Yorktown Energy Partners VI, L.P., et al dated February 22, 2006. (3)
10.4	Subscription Agreements - by and between Hallador Petroleum Company and Hallador Alternative Assets Fund LLC, et al dated February 14, 2006. (4)
10.5	Continuing Guaranty, dated April 19, 2006, by Hallador Petroleum Company in favor of Old National Bank (7)
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 (7)
10.7	Reimbursement Agreement, dated April 19, 2006, between Hallador Petroleum Company and Sunrise Coal, LLC (7)
10.8	Membership Interest Purchase Agreement dated July 31, 2006 by and between Hallador Petroleum Company and Sunrise Coal, LLC. (8)
10.9	Subscription Agreements - by and between Hallador Petroleum Company and Yorktown Energy Partners VII, L.P., et al dated October 5, 2007 (8)
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 (12)
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 (10)
10.12	Amended and Restated Continuing Guaranty, dated as of June 28, 2007, between Hallador Petroleum Company, Sunrise Coal, LLC, and Old National Bank. (11)
10.13	Hallador Petroleum Company Restricted Stock Unit Issuance Agreement dated as of June 28, 2007, between Hallador Petroleum Company and Victor P. Stabio (11)*

10.14	Hallador Petroleum Company Restricted Stock Unit Issuance Agreement dated as of July 19, 2007, between Hallador Petroleum Company and Brent Bilsland (12))*
10.15	Hallador Petroleum Company 2008 Restricted Stock Unit Plan. (13)*
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 (14)
10.17	Form of Hallador Petroleum Company Restricted Stock Unit Issuance Agreement dated July 24, 2008 (14)*
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. (15)
10.19	Continuing Agreement of Guaranty and Suretyship dated December 12, 2008, by Hallador Petroleum Company in favor of PNC Bank, National Association (15)
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 (15)
10.21	Form of Purchase and Sale Agreement dated September 16, 2009 (16)
10.22	Form of Subscription Agreement dated September 15, 2009 (16)
10.23	Form of Hallador Petroleum Company Restricted Stock Unit Issuance Agreement. (16)*
10.24	2009 Stock Bonus Plan (17)*
14	Code Of Ethics For Senior Financial Officers. (6)
21.1	List of Subsidiaries (2)
23.1	Consent of Independent Registered Public Accounting Firm (18)
31	SOX 302 Certifications (18)
32	SOX 906 Certification (18)

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

(1) IBR to Form 8-K dated December 31, 2009.	(10) IBR to Form 10-QSB dated June 30, 2007.
(2) IBR to September 30, 2009 Form 10-Q.	(11) IBR to Form 8-K dated July 2, 2007.
(3) IBR to Form 8-K dated January 3, 2006.	(12) IBR to Form 10-KSB dated December 31, 2007.
(4) IBR to Form 8-K dated January 6, 2006.	(13) IBR to March 31, 2007 Form 10-Q.
(5) IBR to Form 8-K dated February 27, 2006.	(14) IBR to Form 8-K dated July 24, 2008.
(6) IBR to the 2005 Form 10-KSB.	(15) IBR to Form 8-K dated December 12, 2008.
(7) IBR to Form 8-K dated April 25, 2006	(16) IBR to Form 8-K dated September 18, 2009.
(8) IBR to Form 8-K dated August 1, 2006.	(17) IBR to Form S-8 dated December 1, 2009.
(9) IBR to Form 10-QSB dated September 30, 2007.	(18) Filed herewith.

* 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 5, 2010		/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	Chairman	March 5, 2010

/s/Victor P. Stabio	CEO and Director	March 5, 2010

/s/Bryan Lawrence /s/Brent Bilsland /s/John Van Heuvelen	Director President and Director Director	March 5, 2010 March 5, 2010 March 5, 2010

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