Hallador Energy Company
Annual Report 2014

Plain-text annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 FORM 10-K  ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended: December 31, 2014 OR (cid:1) TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 “COAL KEEPS YOUR LIGHTS ON” “COAL KEEPS YOUR LIGHTS ON” Commission file number: 001-3473 HALLADOR ENERGY COMPANY (www.halladorenergy.com) Colorado (State of incorporation) 84-1014610 (IRS Employer Identification No.) 1660 Lincoln Street, Suite 2700, Denver, Colorado (Address of principal executive offices) 80264-2701 (Zip Code) Issuer's telephone number: 303.839.5504 Securities registered pursuant to Section 12(b) of the Exchange Act: NONE Securities registered pursuant to Section 12(g) of the Exchange Act: Common Stock, $.01 par value Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes (cid:1) No (cid:3) Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15 (d) of the Act. Yes (cid:1) No (cid:3) 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 (cid:3) No (cid:1) 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. (cid:3) 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 (cid:3) No (cid:1) 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. (cid:1) Large accelerated filer (cid:1) Non-accelerated filer (do not check if a small reporting company) (cid:3) Accelerated filer (cid:1) 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 (cid:1) No (cid:3) The aggregate market value of the common stock held by non-affiliates (public float) on June 30, 2014 was $100 million based on the closing price reported that date by the NASDAQ of $9.49 per share. As of March 6, 2015 we had 28,962,711 shares outstanding. Portions of our information statement to be filed with the SEC in connection with our annual stockholders’ meeting to be held on Thursday, April 23, 2015 are incorporated by reference into Part III of this Form 10-K.  ITEM 1. BUSINESS. See Item 7- MDA for a discussion of our business. Regulatory Matters Safety and Environmental Regulations Our operations, like operations of other coal companies, are subject to extensive regulation, primarily by federal and state authorities, on matters such as: air quality standards; reclamation and restoration activities involving our mining properties; mine permits and other licensing requirements; water pollution; employee health and safety; management of materials generated by mining operations; storage of petroleum products; protection of wetlands and endangered plant and wildlife protection. Many of these regulations require registration, permitting, compliance, monitoring and self-reporting and may impose civil and criminal penalties for non-compliance. Additionally, the electric generation industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for our coal over time. The possibility exists that new legislation or regulations may be adopted or that the enforcement of existing laws could become more stringent, causing coal to become a less attractive fuel source and reducing the percentage of electricity generated from coal. Future legislation or regulation or more stringent enforcement of existing laws may have a significant impact on our mining operations or our customers’ ability to use coal. While it is not possible to accurately quantify the expenditures we incur to maintain compliance with all applicable federal and state laws, those costs have been and are expected to continue to be significant. Federal and state mining laws and regulations require us to obtain surety bonds or post letters of credit from our banks to guarantee performance or payment of certain long- term obligations, including mine closure and reclamation costs. Federal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, the reclamation and restoration of mining properties after mining has been completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects of mining on groundwater quality and availability. In addition, the industry is affected by significant legislation mandating certain benefits for current and retired coal miners. Numerous federal, state and local governmental permits and approvals are required for mining operations. We believe that we have obtained all permits currently required to conduct our present mining operations. We endeavor to conduct our mining operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time in the industry. None of our violations to date or the monetary penalties assessed have been material. Mine Safety and Health We are subject to health and safety standards both at the federal and state level. The regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters. Mine Safety and Health Administration (MSHA) is the entity responsible for monitoring compliance with the federal mine health and safety standards. MSHA has various enforcement tools that it can use, including the issuance of monetary penalties and orders of withdrawal from a mine or part of a mine. Some, but not all, of the costs of complying with existing regulations and implementing new safety and health regulations may be passed on to customers. MSHA has taken a number of actions to identify mines with safety issues, and has engaged in a number of targeted enforcement, awareness, outreach and rulemaking activities to reduce the number of mining fatalities, accidents and illnesses. There has also been an industry-wide increase in the monetary penalties assessed for citations of a similar nature. 2 Black Lung Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each U.S. coal mine operator must pay federal black lung benefits and medical expenses to claimants who are current and former employees and last worked for the operator after July 1, 1973. Coal mine operators must also make payments to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. Historically, less than 7% of the miners currently seeking federal black lung benefits are awarded these benefits. The trust fund is funded by an excise tax on U.S. production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price. Environmental Laws and Regulations We are subject to various federal, state and local environmental laws and regulations. These laws and regulations place substantial requirements on our coal mining operations, and require regular inspection and monitoring of our mines and other facilities to ensure compliance. We are also affected by various other federal, state and local environmental laws and regulations that our customers are subject to. Surface Mining Control and Reclamation Act. In the U.S., the Surface Mining Control and Reclamation Act of 1977 (SMCRA), which is administered by the Office of Surface Mining Reclamation and Enforcement (OSM), established mining, environmental protection and reclamation standards for all aspects of U.S. surface mining and many aspects of deep mining. Mine operators must obtain SMCRA permits and permit renewals for mining operations from the OSM. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the regulatory authority. Phase I reclamation of our Howesville mine was completed in 2007. We expect to receive final bond release for Howesville in 2015. Additionally, the Prosperity Mine was idled in 2014. We are currently evaluating the best use of the Prosperity Mine facilities. Numerous governmental permits or approvals are required for mining operations. When we apply for these permits and approvals, we may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production or processing of coal may have upon the environment. The authorization, permitting and implementation requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations. Regulations also provide that a mining permit or modification can be delayed, refused or revoked if an officer, director or a shareholder with a 10% or greater interest in the entity is affiliated with another entity that has outstanding permit violations. Thus, past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits. In order to obtain mining permits and approvals from state regulatory authorities, mine operators must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior condition, productive use or other permitted condition. Typically, we submit the necessary permit applications several months before we plan to begin mining a new area. Some of our required permits are becoming increasingly more difficult and expensive to obtain, and the application review processes are taking longer to complete and becoming increasingly subject to challenge. Under some circumstances, substantial fines and penalties, including revocation or suspension of mining permits, may be imposed under the laws described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws. Compliance with these laws has increased the cost of coal mining for domestic coal producers. After a permit application is prepared and submitted to the regulatory agency, it goes through a completeness and technical review. Public notice of the proposed permit is given for a comment period before a permit can be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has the right to comment on and otherwise engage in the permitting process, including public hearings and through intervention in the courts. Before a SMCRA permit is issued, a mine operator must submit a bond or other form of financial security to guarantee the performance of reclamation obligations. 3 The SMCRA Abandoned Mine Land Fund requires a fee on all coal produced in the U.S. The proceeds are used to rehabilitate lands mined and left unreclaimed prior to August 3, 1977 and to pay health care benefit costs of orphan beneficiaries of the Combined Fund created by the Coal Industry Retiree Health Benefit Act of 1992. The fee amount can change periodically. Pursuant to the Tax Relief and Health Care Act of 2006, from October 1, 2007 to September 30, 2012, the fee was $0.315 and $0.135 per ton of surface-mined and underground-mined coal, respectively. From October 1, 2012 through September 30, 2021, the fee is $0.28 and $0.12 per ton of surface-mined and underground-mined coal, respectively. We also pay $.055 and $0.03 per ton to the Indiana Department of Reclamation for surface-mined and underground-mined coal, respectively. The OSM has been in the process of developing a “stream protection rule,” which could result in changes to mining operations under the SMCRA program. The OSM has projected that it will issue a proposed stream protection rule in 2015. Other rulemaking proceedings have been proposed or are being considered by the OSM. Notably, the Proposed Rule for Cost Recovery for Permit Processing, Administration and Enforcement was published in March 2013. Additionally, the OSM is working on a Coal Combustion Residues rulemaking for minefill operations. The agency has projected it may publish a proposed rule by April 2015. These OSM rulemakings and others could have a direct impact on our operations. Clean Air Act (CAA). The Clean Air Act, enacted in 1970, and comparable state laws that regulate air emissions affect our U.S. coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations may occur through the CAA permitting requirements and/or emission control requirements relating to particulate matter (PM), sulfur dioxide and ozone. It is possible that modifications to the national ambient air quality standards (NAAQS) could directly impact our mining operations in a manner that includes, but is not limited to, requiring changes in vehicle emissions standards or resulting in newly designated non-attainment areas. Furthermore, the U.S. Environmental Protection Agency (EPA) in 2009 adopted revised rules to add more stringent PM emissions limits for coal preparation and processing plants constructed or modified after April 28, 2008. Since 2011, the EPA has required underground coal mines to report on their greenhouse gas emissions. The CAA indirectly, but more significantly, affects the U.S. coal industry by extensively regulating the air emissions of sulfur dioxide, nitrogen oxides, mercury, PM and other substances emitted by coal-fueled electricity generating plants. The air emissions programs that may affect our operations, directly or indirectly, include, but are not limited to, the Acid Rain Program, interstate transport rules, New Source Performance Standards (NSPS), Maximum Achievable Control Technology (MACT) emissions limits for Hazardous Air Pollutants, the Regional Haze program and New Source Review. In addition, in recent years the EPA has adopted more stringent NAAQS for PM, nitrogen oxide and sulfur dioxide. In November 2014, the EPA proposed a more stringent NAAQS for ozone. Issuance of the proposed rule complies with a decision of the U.S. District Court for the Northern District of California in April 2014 ordering the EPA to propose a new ozone NAAQS by December 1, 2014 and issue a final rule by October 1, 2015. The actual final rule date remains unknown at this time. More stringent standards may trigger additional control technology for mining equipment, or result in additional challenges to permitting and expansion efforts. Many of these air emissions programs and regulations have resulted in litigation which has not been completely resolved. Proposed NSPS for Fossil Fuel-Fired Electricity Utility Generating Units (EGUs). On April 13, 2012, the EPA published for comment a proposed NSPS for emissions of carbon dioxide for new fossil fuel-fired EGUs (proposed NSPS for new power plants). On September 20, 2013, the EPA revoked its April 13, 2012 proposal and issued a new proposed NSPS for new power plants, using section 111(b) of the CAA. On January 8, 2014, the re-proposal was published in the Federal Register and the comment deadline was set at March 10, 2014. In the February 26, 2014 Federal Register, the EPA issued a Notice of Data Availability (NODA) and technical support document in support of the proposed NSPS for new power plants. After extensions, the public comment period for the re-proposed NSPS for new power plants and NODA closed on May 9, 2014. We believe that any final rules issued by the EPA will be challenged. 4 Proposed Rules for Regulating Carbon Dioxide Emissions From Existing Fossil Fuel-Fired EGUs. On June 2, 2014, the EPA issued and later formally published for comment proposed rules for regulating carbon dioxide emissions from existing fossil fuel- fired EGUs under section 111(d) of the CAA. The public comment period on the proposed rules closed on December 1, 2014. The proposed rules would require that the states individually or collectively create systems that would reduce carbon emissions from any EGU located within their borders. Individual states would have to submit their proposed implementation plans to the EPA within one year after the publication of the final rule. Overall, the proposed rules would attempt to achieve by 2020 a nationwide carbon dioxide reduction of 25% from 2005 baseline emissions and, by 2030, a reduction of 30% from 2005 baseline emissions. The EPA has indicated that it intends to adopt final rules by not later than June 1, 2015. We believe that any final rules issued by the EPA will be challenged. Judicial Challenge to the EPA's Greenhouse Gas (GHG) Regulations. In December 2009, the EPA published its finding that atmospheric concentrations of greenhouse gases endanger public health and welfare within the meaning of the CAA, and that emissions of greenhouse gases from new motor vehicles and motor vehicle engines are contributing to air pollution that are endangering public health and welfare within the meaning of the CAA. In May 2010, the EPA published final greenhouse gas emission standards for new motor vehicles pursuant to the CAA. In a decision issued on June 26, 2012, the U.S. Court of Appeals for the District of Columbia (D.C. Circuit) affirmed the EPA's endangerment finding, its motor vehicle greenhouse gas rule and the tailoring rule. In a decision issued on December 20, 2012, the same court denied petitions to reconsider that decision. On October 15, 2013, the U.S. Supreme Court agreed to review the federal government’s power to regulate GHGs from fixed sources. Six petitions were accepted for review, but a single question was being considered: “Whether the EPA permissibly determined that its regulation of GHG emissions from new motor vehicles triggered permitting requirements under the CAA for stationary sources that emit greenhouse gases.” The U.S. Supreme Court decision issued on June 23, 2014 reversed, in part, and affirmed, in part, the 2012 decision of the D.C. Circuit that upheld the EPA's series of CAA GHG-related regulations. Specifically, the court held that the EPA exceeded its statutory authority when it interpreted the CAA to require PSD and Title V permitting for stationary sources based on their potential GHG emissions. The court noted, however, that the EPA permissibly determined that a source already subject to the PSD program because of its emission of conventional pollutants may be required to limit its GHG emissions by employing the best available control technology for GHGs. Published sources indicate that most of the greenhouse gas emissions that the EPA’s challenged rules contemplated regulating may continue to be regulated after the U.S. Supreme Court’s decision is given effect. Motions by industry groups, certain states, environmental groups and the EPA have since been filed in the D.C. Circuit regarding the effect of the U.S. Supreme Court's decision on existing EPA regulations regarding GHG emissions, with industry groups and certain states asserting that the EPA must undertake new rulemaking if it wishes to regulate the GHG emission sources that the U.S. Supreme Court decided were within the EPA's authority to regulate, and the EPA and environmental groups contending that no new rulemaking is required. Other judicial challenges include actions filed in the D.C. Circuit against the EPA’s proposed rule for regulating carbon dioxide emissions from existing fossil fuel-fired EGUs. One action by an industry plaintiff and another by a coalition of states led by West Virginia assert that the EPA does not have the authority to issue the regulations of existing power plants under section 111(d) of the CAA that it has proposed, although the particulars of the arguments in the two challenges differ. The same industry plaintiff has also filed a claim, which is pending in U.S. District Court for the Northern District of West Virginia, asserting that the EPA has a nondiscretionary duty under the CAA to evaluate potential losses of or shifts in employment in conjunction with regulatory action and seeking an injunction barring the EPA Administrator from promulgating new regulations affecting the coal industry before completing the actions it asserts are required. Cross State Air Pollution Rule (CSAPR). On July 6, 2011, the EPA finalized the CSAPR, which requires the District of Columbia and 27 states from Texas eastward (not including the New England states or Delaware) to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. Under the CSAPR, the first phase of the nitrogen oxide and sulfur dioxide emissions reductions was to commence in 2012 with further reductions effective in 2014. In October 2011, the EPA proposed amendments to the CSAPR to increase emission budgets in ten states, including Texas, and ease limits on market-based compliance options. While the CSAPR had an initial compliance deadline of January 1, 2012, the rule was challenged and, on December 30, 2011, the D.C. Circuit stayed the rule and advised that the EPA was expected to continue administering the Clean Air Interstate Rule until the pending challenges are resolved. The court vacated the CSAPR on August 21, 2012, in a two to one decision, concluding that the rule was beyond the EPA's statutory authority. The U.S. Supreme Court on April 29, 2014 reversed the D.C. Circuit and upheld the CSAPR, concluding generally that the EPA’s development and promulgation of CSAPR was lawful, while acknowledging the possibility that under certain circumstances some states may have a basis to bring a particularized, as-applied challenge to the rule. In October 2014, 5 the D.C. Circuit filed an order lifting its stay of CSAPR and addressing a number of preliminary motions regarding the implementation of the Supreme Court’s remand. Oral argument on the case on remand in the D.C. Circuit is now scheduled for February 25, 2015. Mercury and Air Toxic Standards (MATS). On December 16, 2011, the EPA announced the MATS rule and published it in the Federal Register on February 16, 2012. The MATS rulemaking collectively revised the NSPS for nitrogen oxides, sulfur dioxides and particulate matter for new and modified coal-fueled electricity generating plants, and imposed Maximum Achievable Control Technology (MACT) emission limits on hazardous air emissions from new and existing coal-fueled and oil-fueled electric generating plants. The rule provides three years for compliance and a possible fourth year as a state permitting agency may deem necessary. Some utilities have been moving forward with installation of equipment necessary to comply with MATS, and the EPA and states have been granting additional time beyond the 2015 deadline (but no more than one extra year) for facilities that need more time to upgrade and complete those installations. The rule will likely result in the retirement of certain older coal plants. The D.C. Circuit upheld the NSPS portion of the rulemaking in a unanimous decision on March 11, 2014, and upheld the limits on hazardous air emissions against all challenges on April 15, 2014, in a two-to-one decision. Industry groups and a number of states filed and were granted review of the D.C. Circuit decision in the U.S. Supreme Court. The case will be argued in 2015, with a decision anticipated by June 2015. Clean Water Act (CWA). The CWA of 1972 directly impacts U.S. coal mining operations by requiring effluent limitations and treatment standards for wastewater discharge from mines through the National Pollutant Discharge Elimination System (NPDES). Regular monitoring, reporting and performance standards are requirements of NPDES permits that govern the discharge of water from mine-related point sources into receiving waters. The U.S. Army Corps of Engineers (Corps) regulates certain activities affecting navigable waters and waters of the U.S., including wetlands. Section 404 of the CWA requires mining companies to obtain Corps permits to place material in streams for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities. States are empowered to develop and apply “in stream” water quality standards. These standards are subject to change and must be approved by the EPA. Discharges must either meet state water quality standards or be authorized through available regulatory processes such as alternate standards or variances. “In stream” standards vary from state to state. Additionally, through the CWA section 401 certification program, states have approval authority over federal permits or licenses that might result in a discharge to their waters. States consider whether the activity will comply with their water quality standards and other applicable requirements in deciding whether or not to certify the activity. A draft rule that clarifies waters protected by the CWA was proposed by the EPA in June of 2014. If the rule continues forward, it should be finalized in 2015. This rule is highly controversial and litigation is likely from various stakeholders. If CWA authority is eventually expanded, it may impact our operations in some areas by way of additional requirements. National Environmental Policy Act (NEPA). NEPA, signed into law in 1970, requires federal agencies to review the environmental impacts of their decisions and issue either an environmental assessment or an environmental impact statement. We must provide information to agencies when we propose actions that will be under the authority of the federal government. The NEPA process involves public participation and can involve lengthy timeframes. Resource Conservation and Recovery Act (RCRA). RCRA, which was enacted in 1976, affects U.S. coal mining operations by establishing “cradle to grave” requirements for the treatment, storage and disposal of hazardous wastes. Typically, the only hazardous wastes generated at a mine site are those from products used in vehicles and for machinery maintenance. Coal mine wastes, such as overburden and coal cleaning wastes, are not considered hazardous wastes under RCRA. Subtitle C of RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. On December 19, 2014, the EPA announced the final rule on coal combustion residuals (that is, coal ash). As finalized, the rule continues the exemption of CCR from regulation as a hazardous waste, but does impose new requirements at existing CCR surface impoundments and landfills that will need to be implemented over a number of different time-frames in the coming months and years, as well as at new surface impoundments and landfills. Generally these requirements will increase the cost of CCR management, but not as much as if the rule had regulated CCR as hazardous. This EPA initiative is separate from the OSM CCR rulemaking mentioned above. 6 Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). Although generally not a prominent environmental law in the coal mining sector, CERCLA, which was enacted in 1980, nonetheless may affect U.S. coal mining operations by creating liability for investigation and remediation in response to releases of hazardous substances into the environment and for damages to natural resources. Under CERCLA, joint and several liabilities may be imposed on waste generators, site owners or operators and others, regardless of fault. Toxic Release Inventory. Arising out of the passage of the Emergency Planning and Community Right-to-Know Act in 1986 and the Pollution Prevention Act passed in 1990, the EPA's Toxic Release Inventory program requires companies to report the use, manufacture or processing of listed toxic materials that exceed established thresholds, including chemicals used in equipment maintenance, reclamation, water treatment and ash received for mine placement from power generation customers. Endangered Species Act (ESA). The ESA of 1973 and counterpart state legislation is intended to protect species whose populations allow for categorization as either endangered or threatened. Changes in listings or requirements under these regulations could have a material adverse effect on our costs or our ability to mine some of our properties in accordance with our current mining plans. Use of Explosives. Our surface mining operations are subject to numerous regulations relating to blasting activities. Pursuant to these regulations, we incur costs to design and implement blast schedules and to conduct pre-blast surveys and blast monitoring. The storage of explosives is subject to strict federal regulatory requirements. The U.S. Bureau of Alcohol, Tobacco and Firearms (ATF) regulates the use of explosive blasting materials. In addition to ATF regulation, the Department of Homeland Security is expected to finalize an ammonium nitrate security program rule in 2015. The OSM has also recently initiated a rulemaking addressing nitrous clouds that may be produced during blasting. While such new regulations may result in additional costs related to our surface mining operations, such costs are not expected to have a material adverse effect on our results of operations, financial condition or cash flows. Global Climate In the U.S., Congress has considered legislation addressing global climate issues and greenhouse gas emissions, but to date nothing has been enacted. While it is possible that the U.S. will adopt legislation in the future, the timing and specific requirements of any such legislation are uncertain. In the absence of new U.S. federal legislation, the EPA is undertaking steps to regulate greenhouse gas emissions pursuant to the Clean Air Act. In response to the 2007 U.S. Supreme Court ruling in Massachusetts v. EPA, the EPA has commenced several rulemaking projects as described under “Regulatory Matters-U.S. - Environmental Laws and Regulations.” A number of states in the U.S. have adopted programs to regulate greenhouse gas emissions. For example, 10 northeastern states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont) entered into the Regional Greenhouse Gas Initiative (RGGI) in 2005, which is a mandatory cap-and-trade program to cap regional carbon dioxide emissions from power plants. In 2011, New Jersey announced its withdrawal from RGGI effective January 1, 2012. Six midwestern states (Illinois, Iowa, Kansas, Michigan, Minnesota and Wisconsin) and one Canadian province have entered into the Midwestern Regional Greenhouse Gas Reduction Accord (MGGRA) to establish voluntary regional greenhouse gas reduction targets and develop a voluntary multi-sector cap-and-trade system to help meet the targets. It has been reported that, while the MGGRA has not been formally suspended, the participating states are no longer pursuing it. Seven western states (Arizona, California, Montana, New Mexico, Oregon, Utah and Washington) and four Canadian provinces entered into the Western Climate Initiative (WCI) in 2008 to establish a voluntary regional greenhouse gas reduction goal and develop market-based strategies to achieve emissions reductions. However, in November 2011, the WCI announced that six states had withdrawn from the WCI, leaving California and four Canadian provinces as the remaining members. Of those five jurisdictions, only California and Quebec have adopted greenhouse gas cap-and-trade regulations to date and both programs have begun operating. Many of the states and provinces that left WCI, RGGI and MGGRA, along with many that continue to participate, have joined the new North America 2050 initiative, which seeks to reduce greenhouse gas emissions and create economic opportunities in ways not limited to cap-and-trade programs. In the U.S., several states have enacted legislation establishing greenhouse gas emissions reduction goals or requirements. In addition, several states have enacted legislation or have in effect regulations requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power or that provide financial incentives to electricity suppliers for using renewable energy sources. 7 In 2013, the U.S. and a number of international development banks, including the World Bank, the European Investment Bank and the European Bank for Reconstruction and Development, announced that they would no longer provide financing for the development of new coal-fueled power plants or would do so only in narrowly defined circumstances. Other international development banks, such as the Asian Development Bank and the Japanese Bank for International Cooperation, have continued to provide such financing. The Kyoto Protocol, adopted in December 1997 by the signatories to the 1992 United Nations Framework Convention on Climate Change, established a binding set of emission targets for developed nations. The U.S. signed the Kyoto Protocol but it has never been ratified by the U.S. Senate. There are continuing discussions to develop a treaty to replace the Kyoto Protocol after its expiration in 2012, including at the Cancun meetings in late 2010, the Durban meeting in late 2011 and the Doha meeting in late 2012. At the Durban meeting, an ad hoc working group was established to develop a protocol, another legal instrument or an agreed outcome with legal force under the convention, applicable to all parties. At the Doha meeting, an amendment to the Kyoto Protocol was adopted, which includes new commitments for certain parties in a second commitment period, from 2013 to 2020. Enactment of laws or passage of regulations by the U.S. or some of its states or by other countries regarding emissions from the mining of coal, or other actions to limit such emissions, are not expected to have a material adverse effect on our results of operations, financial condition or cash flows. Enactment of laws or passage of regulations regarding emissions from the combustion of coal by the U.S., some of its states or other countries, or other actions to limit such emissions, could result in electricity generators switching from coal to other fuel sources. Further, policies limiting available financing for the development of new coal-fueled power plants could adversely impact the global demand for coal in the future. The potential financial impact on us of future laws, regulations or other policies will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance on coal as a fuel source. That, in turn, will depend on a number of factors, including the specific requirements imposed by any such laws, regulations or other policies, the time periods over which those laws, regulations or other policies would be phased in, the state of commercial development and deployment of CCS technologies and the alternative markets for coal. In view of the significant uncertainty surrounding each of these factors, it is not possible for us to reasonably predict the impact that any such laws, regulations or other policies may have on our results of operations, financial condition or cash flows. Suppliers The main types of goods we purchase are mining equipment and replacement parts, steel-related (including roof control) products, belting products, lubricants, electricity, fuel and tires. Although we have many long, well-established relationships with our key suppliers, we do not believe that we are dependent on any of our individual suppliers other than for purchases of electricity. The supplier base providing mining materials has been relatively consistent in recent years. Purchases of certain underground mining equipment are concentrated with one principle supplier; however, supplier competition continues to develop. Illinois Basin (ILB) The coal industry underwent a significant transformation in the early 1990s, as greater environmental accountability was established in the electric utility industry. Through the U.S. Clean Air Act, acceptable baseline levels were established for the release of sulfur dioxide in power plant emissions. In order to comply with the new law, most utilities switched fuel consumption to low-sulfur coal, thereby stripping the ILB of over 50 million tons of annual coal demand. This strategy continued until mid 2000 when a shortage of low-sulfur coal drove up prices. This price increase combined with the assurance from the U.S. government that the utility industry would be able to recoup their costs to install scrubbers caused utilities to begin investing in scrubbers on a large scale. With scrubbers, the ILB has reopened as a significant fuel source for utilities and has enabled them to burn lower cost, high sulfur coal. The ILB consists of coal mining operations covering more than 50,000 square miles in Illinois, Indiana and western Kentucky. The ILB is centrally located between four of the largest regions that consume coal as fuel for electricity generation (East North Central, West South Central, West North Central and East South Central). The region also has access to sufficient rail and water transportation routes that service coal-fired power plants in these regions as well as other significant coal consuming regions of the South Atlantic and Middle Atlantic. 8 U. S. Coal Industry According to the EIA, coal is expected to remain the largest energy source of electric power generation in the United States for the foreseeable future. The major coal production basins in the U.S. include Central Appalachia (CAPP), Northern Appalachia (NAPP), Illinois Basin (ILB), Powder River Basin (PRB) and the Western Bituminous region (WB). CAPP includes eastern Kentucky, Tennessee, Virginia and southern West Virginia. NAPP includes Maryland, Ohio, Pennsylvania and northern West Virginia. The ILB includes Illinois, Indiana and western Kentucky. The PRB is located in northeastern Wyoming and southeastern Montana. The WB includes western Colorado, eastern Utah and southern Wyoming. Coal type varies by basin. Heat value and sulfur content are important quality characteristics and determine the end use for each coal type. Coal in the U.S. is mined through surface and underground mining methods. The primary underground mining techniques are longwall mining and continuous (room-and-pillar) mining. The geological conditions dictate which technique to use. Our mines use the continuous technique. In continuous mining, rooms are cut into the coal bed leaving a series of pillars, or columns of coal, to help support the mine roof and control the flow of air. Continuous mining equipment cuts the coal from the mining face. Generally, openings are driven 20’ wide and the pillars are rectangular in shape measuring 40’x 40’. As mining advances, a grid-like pattern of entries and pillars is formed. Roof bolts are used to secure the roof of the mine. Battery cars move the coal to the conveyor belt for transport to the surface. The pillars can constitute up to 50% of the total coal in a seam. The United States coal industry is highly competitive, with numerous producers selling into all markets that use coal. We compete against large producers and hundreds of small producers. Peabody Energy Corporation (NYSE:BTU) and Alliance (NASDAQ:ARLP) are the two largest operators in the ILB producing slightly less than half the ILB’s coal production. There are some that believe natural gas (natgas) will overtake coal as the most economic way to produce electricity in the U.S. In the event the government places a price tag on carbon emissions, natgas would gain another advantage over coal since electricity from coal produces more carbon. The potential exists for natgas producers and utilities to develop a new relationship that has not been possible historically. Employees We have 1,027 employees. Other We have no significant patents, trademarks, licenses, franchises or concessions. Our Denver office is located at 1660 Lincoln Street, Suite 2700, Denver, Colorado 80264, phone 303.839.5504 and Sunrise Coal's corporate office is located at 1183 Canvasback Drive, Terre Haute, Indiana 47802, phone 812.299.2800. Terre Haute is approximately 70 miles west of Indianapolis. Our website is www.halladorenergy.com and Sunrise Coal’s is www.sunrisecoal.com. ITEM 1A. RISK FACTORS. We are not required to provide the information required by this item but most likely next year we will be required. ITEM 1B. UNRESOLVED STAFF COMMENTS . None. ITEM 2. PROPERTIES. See Item 7 MDA for a discussion of our mines. 9 Coal Reserve Estimates “Reserves” are defined by the SEC Industry Guide 7 as that part of a mineral deposit, which could be economically and legally extracted or produced at the time of the reserve determination. “Recoverable” reserves mean coal that is economically recoverable using existing equipment and methods under federal and state laws currently in effect. “Proven (measured) reserves” are defined by Guide 7 as reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established. “Probable reserves” are defined by Guide 7 as reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation. Our reserve estimates were prepared by Samuel Elder and Jacob Gennicks, two of our mining engineers. Mr. Elder is a licensed Professional Engineer in the State of Indiana and has over 25 years experience estimating coal reserves. Mr. Gennicks is a licensed Professional Engineer in the State of Indiana and Illinois and has five years experience estimating coal reserves. Standards set forth by the USGS were used to place areas of the mine reserves into the Proven (measured) and Probable (indicated) categories. Under these standards, coal within 1,320' of a data point is considered to be proven, and coal within 1,320' to 3,960' is placed in the Probable category. All reserves are stated as a final salable product. For the exploration process, core samples are boxed and delivered to an independent lab for analysis. For the production process samples are taken just before the coal is placed in the rail car by an independent lab which later provides the officiating coal analysis for payment. Prior to acquiring coal mineral leases, title abstractors conduct a preliminary title search on the property. This information provides a strong indication of the coal owner, with whom we will enter into a lease. The next step is to execute a lease with the owner, giving us the rights to explore and mine the property. Prior to mining, attorneys review the chain of mineral ownership to verify the lessor is the mineral owner. Prior to purchasing coal properties, we follow a similar process. Inaccuracies in our estimates of our coal reserves could result in decreased profitability from lower than expected revenues or higher than expected costs. Our future performance depends on, among other things, the accuracy of our estimates of our proven and probable coal reserves. We base our estimates of reserves on engineering, economic and geological data assembled, analyzed and reviewed by internal engineers. We update our estimates of the quantity and quality of proven and probable coal reserves annually to reflect the production of coal from the reserves, updated geological models and mining recovery data, the tonnage contained in new lease areas acquired and estimated costs of production and sales prices. There are numerous factors and assumptions inherent in estimating the quantities and qualities of, and costs to mine, coal reserves, including many factors beyond our control, including the following: • quality of the coal; • geological and mining conditions, which may not be fully identified by available exploration data and/or may differ from our experiences in areas where we currently mine; • the percentage of coal ultimately recoverable; • the assumed effects of regulation, including the issuance of required permits, taxes, including severance and excise taxes and royalties, and other payments to governmental agencies; • assumptions concerning the timing for the development of the reserves; and • assumptions concerning equipment and productivity, future coal prices, operating costs, including for critical supplies such as fuel, tires and explosives, capital expenditures and development and reclamation costs. 10 As a result, estimates of the quantities and qualities of economically recoverable coal attributable to any particular group of properties, classifications of reserves based on risk of recovery, estimated cost of production, and estimates of future net cash flows expected from these properties as prepared by different engineers, or by the same engineers at different times, may vary materially due to changes in the above factors and assumptions. Actual production recovered from identified reserve areas and properties, and revenues and expenditures associated with our mining operations, may vary materially from estimates. ITEM 3. LEGAL PROCEEDINGS. None ITEM 4. MINE SAFETY DISCLOSURES See Exhibit 95 to this Form 10-K for a listing of our mine safety violations. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES. Stock Price Information Our common stock is traded on the NASDAQ Capital Market under the symbol HNRG. 63% of our stock is held by our officers, directors and their affiliates. The following table sets forth the high and low closing sales price for the periods indicated: 2015 January 1 through March 4 2014 Fourth quarter Third quarter Second quarter First quarter 2013 Fourth quarter Third quarter Second quarter First quarter Regular and Special Cash Dividends Dividends Paid High Low $ .04 $ 12.67 $ 10.37 .04 .04 .04 .04 .04 .04 .04 12.00 14.08 9.83 8.99 8.55 8.41 8.37 8.35 10.12 9.98 8.51 7.63 6.58 6.82 6.46 6.90 During 2012, we paid three special dividends: $.14, $.50 and $.16, totaling $.80 per share. On April 5, 2013 our Board of Directors approved the adoption of a regular quarterly dividend policy. At March 4, 2015, we had 232 shareholders of record of our common stock; this number does not include the shareholders holding stock in "street name.” We estimate we have over 1,800 street name holders. 11 Equity Compensation Plan Information Restricted Stock Units At December 31, 2014 we had 1,042,000 Restricted Stock Units (RSUs) outstanding and 1,257,900 available for future issuance. The outstanding RSUs have a value of $13 million based on the March 4, 2015 closing stock price of $12.67. On February 1, 2014 we granted 920,000 RSUs to key employees of which 720,000 vest equally over four years and 200,000 over two years. Our stock price on grant date was $7.66. On April 1, 2014, we granted 171,000 RSUs and our stock price was $8.54. On September 2, 2014 we granted 99,000 RSUs and our stock price was $13.56. On three other occasions in 2014, we granted a total of 5,500 RSUs; our stock price on those dates ranged from $11.39 to $14.06. All RSUs granted in 2014, other than those on February 1, cliff vest over three years. In July 2013, we granted 4,000 RSUs with cliff vesting of three years; our stock price on grant date was $8.14. We expect 407,000 RSUs to vest during 2015 under our current vesting schedule. During 2014 and 2013, there were 310,000 and 315,500 RSUs that vested, respectively. On the vesting dates the shares had a value of $3.1 million for 2014 and $2.3 million for 2013. Under our RSU plan participants are allowed to relinquish shares to pay for their required minimum statutory income taxes. Stock-based compensation expense for 2014 was $3.2 million and for 2013 was $2.2 million. For 2015, based on existing RSUs outstanding, stock-based compensation expense will be $3.3 million. Stock Options We have no stock options outstanding. Stock Bonus Plan Our stock bonus plan was authorized in late 2009 with 250,000 shares. Currently, we have about 86,000 shares left in such plan. ITEM 6. SELECTED FINANCIAL DATA. We are not required to provide the information required by this item but most likely next year we will be required. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. Our consolidated financial statements should be read in conjunction with this discussion. Overview The largest portion of our business is devoted to coal mining in the state of Indiana through Sunrise Coal, LLC (a wholly-owned subsidiary) serving the electric power generation industry. We also own a 40% equity interest in Savoy Energy, L.P., a private oil and gas exploration company with operations in Michigan, and a 50% interest in Sunrise Energy, LLC, a private gas exploration company with operations in Indiana. We account for our investments in Savoy and Sunrise Energy using the equity method. On August 29, 2014, we consummated the acquisition of Vectren Fuels, Inc. (VFI) for $311 million. See Note 2 to the financial statements. Vectren Fuels, headquartered in Evansville, Indiana, owned three underground coal mines in southwestern Indiana, including the Oaktown 1 and Oaktown 2 mines in Oaktown, Indiana, and the Prosperity Mine located in Petersburg, Indiana. The Prosperity Mine was idled on August 29, 2014. The two underground mines located near Oaktown, Indiana are seven miles south of our Carlisle underground mine. Oaktown 2 is contiguous to our Carlisle mine and War Eagle reserve. Thus, we intend to mine part of Oaktown 2’s reserve from our Carlisle portal and all of our War Eagle reserve from the Oaktown 2 portal (as noted later in the Reserve Table). 12 Oaktown 1, Oaktown 2, Carlisle and War Eagle are now one large underground mining complex representing 160 million tons of controlled reserves, with three portals, two wash plants and two rail facilities, located on the CSX. We anticipate total capacity for the three mines to be roughly 9.7 million tons annually. Additionally, the capacity of our Ace in the Hole mine is .5 million tons annually. Thus, our total mining capacity is 10.2 million tons annually. Our largest contributor to revenue and earnings has been the Carlisle underground coal mine located in western Indiana, about 30 miles south of Terre Haute. We now expect both Oaktown 1 and Oaktown 2 to significantly contribute to revenue and earnings. For 2014, over 80% of our coal sales were to customers with large scrubbed coal-fired power plants in the state of Indiana. Our mines and coal reserves are strategically located in close proximity to our primary customers, which reduces transportation costs and thus provides us with a competitive advantage with respect to those customers; our closest customer’s plant is 13 miles away and the farthest Indiana customer is 100 miles away. We have access to our primary customers directly through either the CSX railroad (NYSE:CSX) or through the Indiana Rail Road, majority owned by the CSX. We see an increasing demand for coal produced in the Illinois Basin (ILB) in the future. Demand for coal produced in the ILB is expected to grow at a rate faster than overall U.S. coal demand due to ILB coal having higher heating content than Powder River Basin (PRB) and lower cost structure than Central Appalachia (CAPP) coal. Many utilities are scrubbing to meet emission requirements beyond just sulfur compliance, even utilities that burn exclusively PRB. Once scrubbed, those utilities are usually capable of burning ILB coal. It is this trend of new scrubber installations coupled with rising CAPP cost structure that is leading to increased switching from CAPP coal to ILB coal. Some fuel switching will also occur from PRB to ILB in newly scrubbed utilities located near ILB coal supply. The majority of our coal is sold to investment grade customers who have scrubbed, “base load” power plants. Base load power plants are among the lowest cost producers of electricity and the first to dispatch in the power grid. Due to the large investments made to these plants none of these plants are scheduled for retirement; thus we expect to be supplying these plants for many years. It is not economical for the smaller, older, less efficient power plants to install scrubbers and other pollution control devices; accordingly, those type plants most likely will be retired in the coming years. Our Coal Contracts We sell coal to the following customers: Duke Energy Corporation (NYSE:DUK), Hoosier Energy, an electric cooperative, Indianapolis Power & Light Company (IPL), a wholly-owned subsidiary of The AES Corporation (NYSE:AES), Northern Indiana Public Service Co. (NIPSCO), a wholly-owned subsidiary of NiSource Inc. (NYSE:NI) and Vectren Corporation (NYSE:VVC). We also deliver coal to three Florida utilities. We believe these Florida sales are an indication of the trend of ILB coal replacing CAPP coal that has traditionally supplied the southeast markets. The table below illustrates the status of our current coal contracts: Period 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Total Priced Tons Average Price/Ton Committed Unpriced Tons Total Tons 9,341,000 $ 3,369,000 1,450,000 - - - - - - - 14,160,000 1,000,000 1,480,000 2,480,000 2,480,000 2,480,000 2,480,000 2,480,000 2,000,000 1,000,000 17,880,000 9,341,000 4,369,000 2,930,000 2,480,000 2,480,000 2,480,000 2,480,000 2,480,000 2,000,000 1,000,000 32,040,000 44.68 44.03 44.39 13 As set forth in the table above we have 17.88 million tons committed but unpriced through 2024. Roughly 1/3 of these tons reprice every year for a three-year period. Committed tons are a firm commitment, meaning we are required to ship and our customer is required to receive said tons through the duration of the contract. The contracts provide mechanisms for establishing a market- based price. We expect to continue selling a significant portion of our coal under supply agreements with terms of one year or longer. Typically, customers enter into coal supply agreements to secure reliable sources of coal at predictable prices while we seek stable sources of revenue to support the investments required to open, expand and maintain, or improve productivity at the mines needed to supply these contracts. The terms of coal supply agreements result from competitive bidding and extensive negotiations with customers. Current Projects All of our underground coal reserves are high sulfur (4.5 - 6#) with a BTU content in the 11,200 -11,500 range. As discussed below, the Ace surface mine is low sulfur (1.5#) with a BTU content of 11,400. We have no met coal reserves, only steam (thermal) coal reserves. Below is a discussion of our current projects preceded by a table of our coal reserves. Reserve Table - Controlled Tons (in millions): Annual Capacity Year End Reserves 2014 2013 Proven Probable Total Proven Probable Total Carlisle (assigned) Ace in the Hole (assigned) Oaktown 1* (assigned) Oaktown 2* (assigned) War Eagle** (unassigned in 2013) Bulldog (unassigned) Total 3.3 .5 3.2 3.2 43.7 2.7 30.3 47.6 9.5 14.1 15.3 53.2 2.7 44.4 62.9 10.2 19.6 143.9 16.2 55.1 35.8 199.0 Assigned Unassigned 163.2 35.8 199.0 33.5 3.1 8.6 42.1 3.1 27.7 19.6 83.9 15.4 16.2 40.2 43.1 35.8 124.1 45.2 78.9 124.1 * Oaktown 1 and 2 were acquired on August 29, 2014. ** War Eagle reserves will be mined from the Oaktown 2 portal and have been added to the Oaktown 2 reserve base. Carlisle Mine (underground) – Assigned Our coal reserves at December 31, 2014 assigned to the Carlisle Mine were 53 million tons. The mine is located near the town of Carlisle, Indiana in Sullivan County and became operational in January 2007. The coal is accessed with a slope to a depth of 340'. The coal is mined in the Indiana Coal V seam which is highly volatile bituminous coal and is the most economic in Indiana. The Indiana V seam has been extensively mined by underground and surface methods in the general area. The coal thickness in the project area is 4' to 7'. The mine has several advantages as listed below: • SO 2 - Historically, Carlisle has guaranteed a 6# SO 2 product; however, with the addition of the Ace in the Hole Mine we can blend lower sulfur coal with Carlisle coal and guarantee a mid-sulfur product which should command a higher price and increase our customer base. Few mines in the ILB have the ability to offer their customers various ranges of SO 2 . Carlisle has supplied coal to 11 different power plants. • Chlorine - Our reserves have lower chlorine (<0.10%) than average ILB reserves of 0.22%. Much of the ILB’s new production is located in Illinois and possesses chlorine content in excess of .30%. The relatively low chlorine content of our reserves is attractive to buyers given their desire to limit the corrosive effects of chlorine in their power plants. 14 • Transportation - Carlisle has a double 100 rail car loop facility and a four-hour certified batch load-out facility connected to the CSX railroad. The Indiana Rail Road (INRD) also has limited running rights on the CSX to our mine. Dual rail access gives us a freight advantage to more customers. Long term, the CSX anticipates our coal being shipped to southeast markets via their railroad. We sell our coal FOB the mine and substantially all of our coal is transported by rail. However, on occasion we have shipped to three power plants via truck. Ace in the Hole Mine (Ace) (surface) – Assigned In November 2012 we purchased for $6 million permitted fee coal reserves, coal leases and surface properties near Clay City, Indiana in Clay County. The Ace mine is 42 road miles northeast of the Carlisle Mine. We control 2.7 million tons of proven coal reserves of which we own .9 million tons in fee. We mine two primary seams of low sulfur coal which make up 2.6 million of the 2.7 million tons controlled. Both of the primary seams are low sulfur (<2# SO 2 ) . Mine development began in late December 2012, and we began shipping coal in late August 2013. We truck low sulfur coal from Ace to Carlisle and/or Oaktown to blend with high sulfur coal. Many utilities in the southeastern U.S. have scrubbers with lower sulfur limits (4# SO 2 ) which cannot accept the higher sulfur contents of the ILB (4.5# - 6# SO 2 ). Blending high sulfur coal to a lower sulfur specification enables us to market our high sulfur coals to more customers. We also expect to ship low sulfur coal from Ace direct to unscrubbed customers that require low sulfur (1.5# SO 2 ). We expect the maximum capacity of Ace to be 500,000 tons annually. The Ace mine is a multi-seam open pit strip mine. The majority of the seams are sold raw, but some of the seams will be washed prior to sales depending on quality. To convert the tons sold raw the in-place tonnage is taken times a pit recovery of 94% based on seam thickness. To convert the tons sold washed the in-place tonnage is taken times a pit recovery based on seam thickness then reduced by the projected plant recovery of 72%. Oaktown 1 Mine (underground) – Assigned We have 44 million tons controlled and rated proved and probable of the Indiana coal V seam. All reserves are located in Knox County, IN. Oaktown 2 Mine / War Eagle reserve (underground) – Assigned We have combined 20 million tons of our Oaktown 2 Mine with 43 million tons from our War Eagle reserve to create a combined 63 million tons of reserve based in both Knox County, Indiana and Lawrence County, Illinois. Both the Oaktown 2 reserve and War Eagle reserve will be mined through the Oaktown 2 portal. In future reporting we will only refer to the combined reserve as Oaktown 2. Access to the Oaktown 1 mine is via a 90 foot deep box cut and a 2,200 foot slope on a 14 percent grade, reaching coal in excess of 375 feet below the surface. Access to the Oaktown 2 mine is via an 80 foot deep box cut and a 2,600 foot slope on a 14 percent grade, reaching coal in excess of 400 feet below the surface. Our underground mines are room and pillar mines meaning that main airways and transportation entries are developed and maintained while remote-controlled continuous miners extract coal from so-called rooms by removing coal from the seam, leaving pillars to support the roof. Shuttle cars or similar transportation are used to transport coal to a conveyor belt for transport to the surface. The two Oaktown mines are separated by a sandstone channel. The coal seam thickness ranges from 4 feet to over 9 feet. The mine’s wash plant was originally sized to process 800 tons per hour and has been expanded to 1,600 tons per hour to accommodate the second mine. The two mines are connected to a railway equipped to handle 110 to 120 car unit trains. Coal is also transported via truck to customers. Bulldog Mine (underground) – Unassigned We have leased roughly 19,300 acres in Vermillion County, Illinois near the village of Allerton. Based on our reserve estimates we currently control 35.8 million tons of coal reserves. A considerable amount of our leased acres has yet to receive any exploratory drilling, thus we anticipate our controlled reserves to grow as we continue drilling. The permitting process was started in the summer of 2011, and we filed the formal permit with the state of Illinois and the appropriate Federal regulators during June 2012. In July 2014, we were notified by the Illinois Department of Natural Resources (ILDNR) that our permit had been deemed complete which starts the timeline for the ILDNR public review process. It is our estimation that our permit will be approved or denied in 2015. 15 Full-scale mine development will not commence until we have a sales commitment. We estimate the costs to develop this mine to be $150 million at full capacity of three million tons annually. Unassigned reserves represent coal reserves that would require new mineshafts, mining equipment, and plant facilities before operations could begin on the property. The primary reason for this distinction is to inform investors which coal reserves will require substantial capital expenditures before production can begin. Mine and Wash Plant Recovery Carlisle Bulldog Oaktown 1 Oaktown 2 Ohio River Terminal Mine recovery Wash plant recovery 53 % 45 % 49 % 49 % 81 % 77 % 81 % 81 % On May 31, 2013, we purchased for $2.8 million a multi-commodity truck/barge terminal. Over 17 acres of secured area is available. The terminal is at mile point 743.8 on the Indiana bank of the Ohio River near the William Natcher Bridge between Rockport and Grandview, Indiana. Currently the dock will handle third party commodities. In the long term, we plan to ship coal through the dock. The terminal is in close proximity to the NS railroad, the CSX railroad, and American Electric Power's Rockport generating power plant. Liquidity and Capital Resources Our capex budget for 2015 is $37.6 million, of which $26.6 million is for maintenance capex. Cash from operations should fund these expenditures. Our bank debt at February 27, 2015 was $296 million compared to $345 million at September 30, 2014 and $306 million at December 31, 2014. We have no material off-balance sheet arrangements. Capital Expenditures (capex) For 2014 our capex was about $25.8 million allocated as follows (in 000’s): Carlisle - maintenance capex (approximately $5/ton) Oaktown - maintenance capex (approximately $3/ton) Ace - surface equipment Other projects Capex per the Cash Flow Statement 16 $ $ 16.7 6.3 2.0 0.8 25.8 Results of Operations The column for the 3 rd and 4 th quarter of 2014 in the table below includes the mines acquired from Vectren on August 29, 2014. Quarterly coal sales and cost data (in 000’s, except for per ton data): Tons sold Coal sales Average price/ton Wash plant recovery in % Operating costs Average cost/ton Margin Margin/ton Capex Maintenance capex Maintenance capex/ton Tons sold Coal sales Average price/ton Wash plant recovery in % Operating costs Average cost/ton Margin Margin/ton Capex Maintenance capex Maintenance capex/ton 1 st 2014 2 nd 2014 3 rd 2014 4 th 2014 T4Qs $ $ 776 33,016 $ 42.55 66 23,158 $ 29.84 9,858 12.71 2,936 2,650 3.41 847 36,130 $ 42.66 68 26,209 $ 30.94 9,921 11.72 6,190 3,974 4.69 1,500 64,764 $ 43.18 64 52,957 $ 35.30 11,807 7.88 5,200 4,756 3.17 2,275 99,992 $ 43.95 67 67,367 $ 29.61 32,625 14.34 11,509 11,162 4.91 5,398 233,902 43.33 66 169,691 31.43 64,211 11.90 25,835 22,542 4.17 1 st 2013 2 nd 2013 3 rd 2013 4 th 2013 T4Qs $ $ 840 33,995 $ 40.47 74 23,601 $ 28.10 10,394 12.37 8,604 3,516 4.19 774 34,149 $ 44.12 71 22,508 $ 29.08 11,641 15.04 6,174 2,727 3.52 817 34,985 $ 42.82 68 23,800 $ 29.13 11,185 13.69 8,780 5,638 6.90 757 34,307 $ 45.32 63 24,202 $ 31.97 10,105 13.35 7,834 2,721 3.59 3,188 137,436 43.11 69 94,111 29.52 43,325 13.59 31,392 14,602 4.58 During 2014, much of management’s time, effort and attention was focused on the Vectren Fuels acquisition, a transaction that essentially tripled our size. Two thirds of our employees were new to us in September 2014 and we continue to spend time integrating them into our methodologies. We are extremely grateful for the time, effort and dedication of our employees that made the transaction possible. Additionally, rail service was poor throughout the industry in 2014. Unfortunately, we were not immune from this issue. Of our eight contracted customers, three struggled to provide us with the adequate freight. We made several changes to improve transportation in 2015 and so far the results are encouraging. We realize the combination of poor transportation and the challenge of acquiring Vectren Fuels did not help contain our costs structure throughout much of 2014. In the 4 th quarter, we were able to reduce our costs to $29.61/ton, a significant improvement over the 3 rd quarter per ton costs of $35.30. We believe we will be able to maintain our cost structure below $30/ton in 2015. 17 2014 v. 2013 For 2014, we sold 5,398,000 tons at an average price of $43.33/ton. For 2013, we sold 3,188,000 tons at an average price of $43.11/ton. The increase is attributable to the Vectren acquisition. Operating costs and expenses averaged $31.43/ton in 2014 compared to $29.52 in 2013. The reasons for the increase are discussed above. Our Indiana employees totaled 1,018 at December 31, 2014 compared to 373 at December 31, 2013. SG&A expense increased significantly for several reasons: (i) contributions to political candidates and PACs who support the coal mining industry increased by $200,000, (ii) stock based compensation increased by $850,000; (iii) audit and tax fees increased by $310,000; (iv) employee related costs increased by $700,000 and (v) ongoing expenses resulting from the VFI acquisition was $1 million. We also paid $1 million in performance bonuses during December 2014 relating to the VFI acquisition. An additional $2 million in performance bonuses could be paid in December 2015 if certain EBITDA metrics are met. Net Income per Share Basic and diluted Basic and diluted MSHA Reimbursements 1 st 2014 $ 0.12 $ 1 st 2013 $ 0.19 $ 2 nd 2014 3 rd 2014 4 th 2014 0.10 $ (0.20 ) $ .33 2 nd 2013 3 rd 2013 4 th 2013 0.28 $ 0.16 $ 0.16 Some of our legacy coal contracts allow us to pass on certain costs incurred resulting from changes in costs to comply with mandates issued by MSHA or other government agencies. We do not recognize any revenue until customers have notified us that they accept the charges. We submitted our incurred costs for 2011 in October 2012 for $3.7 million. $2.1 million in reimbursements were recorded in the first quarter 2013 and $1.6 million were recorded in the fourth quarter. Based on past experience we expect to collect the 2012 and 2013 costs in 2015. Due to the time involved relating to the Vectren acquisition, we do not expect to submit our incurred costs for 2012 until the first quarter of 2015. Income Taxes Our effective tax rate (ETR) for 2014 was 4.5% compared to 25% for 2013. The low ETR for 2014 is due primarily to the reduction in the Indiana state income tax rate. For 2015 we estimate our ETR to be comparable to the 2013 rate. 40% Ownership in Savoy Savoy operates almost exclusively in Michigan. They have an interest in the Trenton-Black River Play (TBR) in southern Michigan. They hold 136,000 gross acres (68,000 net) in this area. During 2014 Savoy drilled 21 gross wells in the TBR of which 6 were dry, 12 were successful, and 3 are still being evaluated. During 2013, Savoy drilled 30 gross wells in this play of which 13 were dry and 17 were successful. Drilling locations in this play are identified based on the evaluation of extensive 3-D seismic shoots. Savoy operates their own wells and their working interest averages between 30 and 60% and their net revenue interest averages between 25 and 48%. Savoy’s net daily oil production currently averages 875 barrels. Savoy has an interest in 112 gross wells (41 net). Our 45% ownership was decreased to 40% on October 1, 2014 due to the exercise of options by Savoy’s management. Late in 2013 Savoy engaged Energy Spectrum Advisors Inc. (ESA) to market its Trenton-Black River oil properties located in southeast Michigan. No acceptable offers were received. Marketing efforts are on hold until oil prices recover. 18 Savoy made a $12 million cash distribution in early October 2014; our share was $4.9 million; such amount was applied toward our bank debt. The tables below provides detail for Savoy’s operations for the last two years; such unaudited amounts are to the 100%, in other words not shown proportionate to our interest (financial statement data in thousands): Revenue: Oil NGLs (natural gas liquids) Natgas Contract drilling Other Total revenue Costs and expenses: LOE (lease operating expenses) Severance tax Contract drilling costs DD&A (depreciation, depletion & amortization) G&G (geological and geophysical costs) Dry hole costs Impairment of unproved properties Other exploration costs G&A (general & administrative) Total expenses Net income The information below is not in thousands: The data below is based on 2014 average first-of-month prices: Oil production – barrels Average oil prices/barrel Oil reserves in barrels NGL reserves in barrels Natgas reserves in Mcf Oil prices/barrel used for PV 10 PV 10: proved reserves PV 10: proved developed reserves The data below is based on current and future NYMEX strip prices: Oil reserves in barrels NGL reserves in barrels Natgas reserves in Mcf Oil prices/barrel used for PV 10 PV 10: proved reserves PV 10: proved developed reserves 2014 2013 31,569 $ 934 1,124 3,579 4,377 41,583 4,335 2,493 2,767 6,537 4,155 2,830 3,933 441 1,863 29,354 12,229 $ 32,057 900 709 5,409 3,173 42,248 3,262 2,476 3,520 5,802 5,084 3,066 3,999 451 1,662 29,322 12,926 $ $ $ 357,490 88.3 $ 1,688,000 98,000 1,124,000 89.14 $ 337,950 95 3,246,000 218,000 2,875,000 $ 94.66 $ 85,312,000 $ 200,707,000 $ 60,181,000 $ 105,922,000 1,565,000 92,000 1,014,000 $ 59.12 $ 47,450,000 $ 33,347,000 The data below is shown proportionate to our approximate 40% (45% for 2013) ownership in Savoy. Based on SEC rules using average first-of-month prices for the year: PV 10: proved reserves PV 10: proved developed reserves Based on current and future NYMEX strip prices: PV 10: proved reserves PV 10: proved developed reserves $ 34,100,000 $ 90,800,000 $ 24,072,000 $ 47,930,000 $ 18,980,000 $ 13,340,000 19 Critical Accounting Estimates We believe that the estimates of our coal reserves and our deferred tax assets and liability accounts are our only critical accounting estimates. The reserve estimates are used in the DD&A calculation, in our impairment test if and when circumstances indicate the need for measurement, and in our internal cash flow projections. If these estimates turn out to be materially under or over-stated, our DD&A expense and impairment test may be affected. Furthermore, if our coal reserves are materially overstated, our liquidity and stock price could be adversely affected. We account for business combinations using the purchase method of accounting. The purchase method requires us to determine the fair value of all acquired assets, including identifiable intangible assets and all assumed liabilities. The total cost of acquisitions is allocated to the underlying identifiable net assets, based on their respective estimated fair values. Determining the fair value of assets acquired and liabilities assumed requires management's judgment and the utilization of independent valuation experts, and often involves the use of significant estimates and assumptions, including assumptions with respect to future cash inflows and outflows, discount rates and asset lives, among other items. The fair value of our interest rate swaps is determined using a discounted future cash flow model based on the key assumption of anticipated future interest rates. 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. During 2012 the IRS completed an examination of our 2009 and 2010 federal tax returns and there were no significant adjustments. During 2012, the State of Indiana completed their examination of our 2008-2010 returns and no adjustments were proposed. We believe that our income tax filing positions and deductions will be sustained on audit and do not anticipate any adjustments that will result in a material change to our consolidated financial position. Yorktown Distributions As previously disclosed, Yorktown Energy Partners and its affiliated partnerships (Yorktown) have made eight distributions to their numerous partners totaling 6 million (750,000 per distribution) shares since May 2011. In the past, these distributions were made soon after we filed our Form 10-Qs and Form 10-Ks. Currently they own 9.7 million shares of our stock representing about 33% of total shares outstanding. Yorktown last distributed shares in August of 2013. We have been informed by Yorktown that they have not made any determination as to the disposition of their remaining Hallador stock. While we do not know Yorktown’s ultimate strategy to realize the value of their Hallador investment for their partners, we expect that over time such distributions will increase our liquidity and float. If we are advised of another Yorktown distribution, we will timely report such on a Form 8-K. New Accounting Pronouncements None of the recent FASB pronouncements will have any material effect. 20 Below is a map that shows the locations of our mines. Railroad Legend: CSX – CSX Railroad INRD – Indiana Rail Road ISRR – Indiana Southern Railroad NS – Norfolk Southern Railway ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. We are not required to provide the information required by this item but most likely next year we will be required 21 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. Report of Independent Registered Public Accounting Firm Consolidated Balance Sheet Consolidated Statement of Comprehensive Income Consolidated Statement of Cash Flows Consolidated Statement of Stockholders' Equity Notes to Consolidated Financial Statements We are not required to provide supplementary data but most likely next year we will be required. 22 23 24 25 26 27 28 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders Hallador Energy Company Denver, Colorado We have audited the accompanying consolidated balance sheet of Hallador Energy Company (the “Company”) as of December 31, 2014 and 2013, and the related consolidated statements of comprehensive income, cash flows, and stockholders' equity for each of the years in the two-year period ended December 31, 2014. We also have audited the Company’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Hallador Energy Company as of December 31, 2014 and 2013, and the results of their operations and theirs cash flows for each of the years in the two-year period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, Hallador Energy Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control – Integrated Framework (2013) , issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded Vectren Fuels (“Vectren ”) from its assessment of internal control over financial reporting as of December 31, 2014 because Vectren was acquired by the Company during August 2014. We have also excluded Vectren from our audit of internal control over financial reporting. Vectren accounted for approximately 55% of total assets and 40% of net sales as reported in the Company’s consolidated financial statements as of and for the year ended December 31, 2014. /s/ EKS&H LLLP EKS&H LLLP March 5, 2015 Denver, Colorado 23 Consolidated Balance Sheet As of December 31, (in thousands, except per share data) ASSETS Current assets: Cash and cash equivalents Marketable securities Accounts receivable Prepaid income taxes Coal inventory Parts and supply inventory Other Total current assets Coal properties, at cost: Land and mineral rights Buildings and equipment Mine development Less - accumulated DD&A Investment in Savoy Investment in Sunrise Energy Other assets (Note 7) LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Current portion of bank debt Accounts payable and accrued liabilities Total current liabilities Long-term liabilities: Bank debt Deferred income taxes Asset retirement obligations Other Total long-term liabilities Total liabilities Commitments and contingencies Stockholders' equity: Preferred Stock, $.10 par value, 10,000 shares authorized; none issued Common stock, $.01 par value, 100,000 shares authorized; 28,962 and 28,751 shares outstanding, respectively Additional paid-in capital Retained earnings Accumulated other comprehensive income Total stockholders’ equity See accompanying notes. 24 $ $ $ 2014 2013 13,469 $ 1,656 27,297 5,791 19,722 14,919 1,555 84,409 118,053 321,730 124,435 564,218 (106,608 ) 457,610 13,896 4,821 18,849 579,585 $ 21,875 $ 28,105 49,980 284,470 41,581 12,074 1,605 339,730 389,710 16,228 10,577 5,470 4,778 2,826 291 40,170 26,476 148,077 85,333 259,886 (77,545 ) 182,341 16,733 4,573 15,382 259,199 10,357 10,357 16,000 43,304 5,290 2,128 66,722 77,079 289 90,218 99,003 365 189,875 579,585 $ 287 87,872 93,582 379 182,120 259,199 $ Consolidated Statement of Comprehensive Income For the years ended December 31, (in thousands, except per share data) Revenue: Coal sales Equity income – Savoy Equity income - Sunrise Energy Liability extinguishment (Note 10) Other (Note 7) Costs and expenses: Operating costs and expenses DD&A Coal exploration costs SG&A Interest (1) Vectren deal costs (Note 2) Income before income taxes Less income taxes: Current Deferred Net income* Net income per share (Note 11): Basic Diluted Weighted average shares outstanding: Basic Diluted 2014 2013 $ 233,902 $ 5,272 248 1,749 241,171 169,691 29,262 2,362 12,039 9,059 8,057 230,470 137,436 5,827 629 4,300 5,678 153,870 94,111 18,585 2,360 7,669 1,547 124,272 10,701 29,598 2,205 (1,723 ) 482 (266 ) 7,441 7,175 $ 10,219 $ 22,423 $ $ 0.34 $ 0.34 $ 0.78 0.78 28,776 28,776 28,595 28,906 * There is no material difference between net income and comprehensive income. (1) Interest expense for 2014 includes $700,000 for the net change in the estimated fair value of our interest rate swaps and $1 million for expensing deferred financing costs relating to our old credit agreement. See accompanying notes. 25 Consolidated Condensed Statement of Cash Flows For the years ended December 31, (in thousands) Operating activities: Net income Liability extinguishment Deferred income taxes Equity income – Savoy and Sunrise Energy Cash distributions from Savoy DD&A Change in fair value of interest rate swaps Amortization and write off of deferred financing costs Accretion of ARO Stock-based compensation Taxes paid on vesting of RSUs Change in current assets and liabilities: Accounts receivable Coal inventory Parts and supply inventory Income taxes Accounts payable and accrued liabilities Other Cash provided by operating activities Investing activities: Capital expenditures for coal properties Ohio River terminal Vectren acquisition Other Cash used in investing activities Financing activities: Payments of bank debt Bank borrowings Deferred financing costs Dividends Cash provided by financing activities Decrease in cash and cash equivalents Cash and cash equivalents, beginning of year Cash and cash equivalents, end of year Cash paid for interest Cash paid for income taxes, net Increase in ARO Capital expenditures included in accounts payable See Note 2 for assets and liabilities assumed resulting from the Vectren acquisition. See accompanying notes. 26 2014 2013 $ 10,219 $ (1,723 ) (5,520 ) 8,109 29,262 658 1,572 534 3,220 (1,067 ) (324 ) 6,540 1,083 (160 ) 1,409 2,054 55,866 (25,835 ) (311,453 ) (337,288 ) (59,655 ) 350,000 (6,884 ) (4,798 ) 278,663 (2,759 ) 16,228 13,469 $ 5,008 $ 2,334 6,550 748 $ $ 22,423 (4,300 ) 7,441 (6,456 ) 1,325 18,585 299 182 2,155 (780 ) (2,394 ) (2,436 ) (562 ) (6,814 ) 1,130 (2,617 ) 27,181 (31,392 ) (2,836 ) 263 (33,965 ) 4,600 (3,476 ) 1,124 (5,660 ) 21,888 16,228 1,028 6,045 2,535 84 Consolidated Statement of Stockholders’ Equity (in thousands) Common Common Additional Paid- Retained Shares Stock in Capital Earnings AOCI* Total Balance January 1, 2013 Adjustment – (Note 1) Stock-based compensation Stock issued on vesting of RSUs Taxes paid on vesting of RSUs Dividends Net income Other Balance December 31, 2013 Stock-based compensation Stock issued on vesting of RSUs Taxes paid on vesting of RSUs Dividends Net income Other Balance December 31, 2014 28,529 $ 285 $ 86,576 $ 75,118 $ (483 ) 13 316 (107 ) 2 2,155 (780 ) (3,476 ) 22,423 (79 ) 28,751 7 310 (106 ) 287 87,872 93,582 2 3,220 (1,067 ) (4,798 ) 10,219 193 28,962 $ 289 $ 90,218 $ 99,003 $ 30 $ 162,009 (483 ) 2,155 2 (780 ) (3,476 ) 22,423 349 270 379 182,120 3,220 2 (1,067 ) (4,798 ) 10,219 (14 ) 179 365 $ 189,875 *Accumulated Other Comprehensive Income See accompanying notes. 27 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) and Sunrise’s wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. We are engaged in the production of steam coal from mines located in western Indiana. We own a 40% equity interest in Savoy Energy, L.P., a private oil and gas company which has operations in Michigan and a 50% interest in Sunrise Energy, LLC, a private entity engaged in natgas operations in the same vicinity as the Carlisle mine. Reclassification To maintain consistency and comparability, certain amounts in the 2013 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 (including depreciation thereto) 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 mining equipment, coal properties are depreciated using the units-of-production method over the estimated recoverable reserves. Surface and underground mining equipment is depreciated using estimated useful lives ranging from three to twenty-five 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 reserves. Asset Retirement Obligations (ARO) - Reclamation At the time they are incurred, legal obligations associated with the retirement of long-lived assets are reflected at their estimated fair value, with a corresponding charge to mine development. Obligations are typically incurred when we commence development of underground and surface mines, and include reclamation of support facilities, refuse areas and slurry ponds. Obligations are reflected at the present value of their future cash flows. We reflect accretion of the obligations for the period from the date they are incurred through the date they are extinguished. The asset retirement obligation assets are amortized using the units-of-production method over estimated recoverable (proved and probable) reserves. We are using discount rates ranging from 5.5% to 10%. 28 Federal and state laws require that mines be reclaimed in accordance with specific standards and approved reclamation plans, as outlined in mining permits. Activities include reclamation of pit and support acreage at surface mines, sealing portals at underground mines, and reclamation of refuse areas and slurry ponds. We assess our ARO at least annually and reflect revisions for permit changes, changes in our estimated reclamation costs and changes in the estimated timing of such costs. The table below (in thousands) reflects the changes to our ARO: Balance beginning of year Accretion Vectren acquistion Additions Other Balance end of year Statement of Cash Flows 2014 2013 $ $ 5,290 $ 534 6,550 (300 ) 12,074 $ 2,573 182 2,535 5,290 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. Net Income per Share Basic net income per share is computed on the basis of the weighted average number of shares of common stock outstanding during the period. Diluted net income 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 restricted stock units and are included in basic net income per share. Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Actual amounts could differ from those estimates. The most significant estimates included in the preparation of the financial statements are related to (i) fair value estimates relating to business combinations, (ii) deferred income tax assets and liabilities, and (iii) coal reserves. Derivatives We recognize at fair value all contracts meeting the definition of a derivative as assets or liabilities in the consolidated balance sheet, with the exception of our coal contracts for which we elected to apply a normal purchases and normal sales exception. Changes in fair value are recognized into income. 29 Business Combinations We account for business combinations using the purchase method of accounting. The purchase method requires us to determine the fair value of all acquired assets, including identifiable intangible assets and all assumed liabilities. The total cost of acquisitions is allocated to the underlying identifiable net assets, based on their respective estimated fair values. Determining the fair value of assets acquired and liabilities assumed requires management's judgment and the utilization of independent valuation experts, and often involves the use of significant estimates and assumptions, including assumptions with respect to future cash inflows and outflows, discount rates and asset lives, among other items. Revenue Recognition We recognize revenue from coal sales at the time risk of loss passes to the customer at contracted amounts and amounts are deemed collectible. Long-term Contracts As of December 31, 2014, we are committed to supply to our customers 32 million tons of coal through 2024 of which 14 million tons are priced. During 2014 five of our customers accounted for 75% of our coal sales: one for 35%, the second for 12%, the third for 11%, the fourth for 9% and the fifth for 8%. During 2013, four of our customers accounted for 94% of our coal sales: one for 39%, the second for 29%, the third for 14% and the fourth for 12%. 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 two to four years) using the straight-line method. New Accounting Pronouncements None of the recent FASB pronouncements will have any material effect on us. Subsequent Events We have evaluated all subsequent events through the date the financial statements were issued. No material recognized or non- recognizable subsequent events were identified. Correction of Immaterial Errors- Cost of Sales During the fourth quarter of 2014, we identified errors to the consolidated financial statements for the years 2011 - 2014 (and for all interim periods therein) related to operating costs. We were inappropriately reconciling parts and supplies inventory related to a parts and components agreement with one of our vendors and the error was discovered when we were comparing amounts for the fourth quarter of 2014. The effect of correcting these errors to the 2013 consolidated financial statements was to decrease net income by $731,000. The effect for 2011 and 2012 totaled $483,000 and is reflected as a reduction in beginning retained earnings. The effect for 2014 was to reduce fourth quarter net income by $334,000. Management evaluated the materiality of all the errors described above from a qualitative and quantitative perspective. Based on such evaluation, we have concluded that while the accumulation of these errors was significant to the year ended December 31, 2014, their correction would not be material to any individual prior period, nor did they have an effect on the trend of financial results, taking into account the requirements of the Securities and Exchange Commission (SEC) Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements (SAB 108). Accordingly, we are correcting these errors in every affected period in the 2014 and 2013 Consolidated Financial Statements included in this Form 10-K. 30 (2) Vectren Fuels Acquisition On August 29, 2014, we consummated the acquisition of all the common stock of Vectren Fuels, Inc. (VFI) for $311 million, which was accounted for as a business acquisition requiring measurement of acquired assets and assumed liabilities at their estimated fair value in applying purchase accounting. The estimated fair values are based on market participant assumptions. The acquisition was financed through a new debt facility, and the preliminary purchase price allocation and use of proceeds from the new debt facility were as follows (assets not received or liabilities not assumed were retained by the parent company of VFI): Assets received: Accounts receivable Coal inventory Parts and supply inventory Advance royalties Prepaid expenses Land and mineral rights Mine development Buildings and equipment Total assets received Liabilities assumed: Accounts payable and accrued liabilities Asset retirement obligations Total liabilities assumed Total consideration paid for VFI $ 16,879 21,484 13,180 711 701 87,293 37,485 152,977 330,710 12,707 6,550 19,257 $ 311,453 The initial purchase price was $319 million, which was adjusted downward by $8 million in November 2014 due to post closing adjustments. The closing expenses include certain contract termination costs related to the termination of a contract post combination, which was to our benefit. The acquisition generated $95 million of revenue and $19.7 million of pretax income since the August 29, 2014 acquisition date, and these amounts are included in our operations for the year ended December 31, 2014. 31 The following unaudited pro forma information has been prepared for illustrative purposes only and assumes the acquisition occurred on January 1, 2013. The unaudited pro forma results have been prepared based on estimates and assumptions, which we believe are reasonable, however, they are not necessarily indicative of the consolidated results of operations had the acquisition occurred on January 1, 2013, or of future results of operations. VFI deal related costs of $9 million (including $1 million for the write off of deferred financing costs related to the old credit agreement) have been excluded from the pro forma amounts. Total revenues: As reported Pro forma Net income: As reported Pro forma Basic net income per share: As reported Pro forma (3) Bank Debt Year Ended December 31, 2014 2013 (In thousands, except per share data) $ $ $ $ $ $ 241,171 $ 462,000 $ 10,219 $ 39,068 $ 0.34 $ 1.36 $ 153,870 447,500 22,423 46,503 0.78 1.63 To finance the VFI acquisition (see Note 2) we entered into a credit agreement with PNC Bank as administrative agent for a group of several other banks. The credit agreement allows for a $250 million revolver and a $175 million term loan. Our debt at December 31, 2014 is $306 million (term-$161, revolver-$145). The maximum that we could borrow at December 31, 2014 was $365 million due to the covenants. The credit facility is collateralized by substantially all of Sunrise’s assets and we are the guarantor. Bank fees and other costs incurred in connection with this new facility were about $6.8 million which were deferred and are being amortized over five years. Deferred financing costs, associated with our previous credit facility, approximated $1 million and were expensed. All borrowings under the credit agreement bear interest at LIBOR (16 bps at December 31, 2014) plus 2.25% if the leverage ratio is less than 1X; LIBOR plus 2.5% if the leverage ratio is over 1X but less than 1.5X; LIBOR plus 2.75% if the ratio is over 1.5X but less than 2X; LIBOR plus 3% if the ratio is over 2X but less than 2.5X and at LIBOR plus 3.5% if the leverage ratio is over 2.5X. The computed ratio at December 31, 2014 was 2.73X. We are required to pay at the highest rate (LIBOR plus 3.5%) through the first quarter of 2015. The maximum leverage ratio is currently 3.25X. The leverage ratio is equal to funded debt/EBITDA. We entered into swap agreements to fix the LIBOR component of the interest rate to achieve an effective fixed rate of no greater than 5% on 100% ($175 million) of the term loan and on $100 million of the revolver. The revolver swaps step down 10% each quarter commencing March 31, 2016. At December 31, 2014 these two interest rate swaps had an estimated net fair value (liability) of $.7 million consisting of a long term asset of $1.7 million and a current liability of $2.4 million. Such amounts are included in other long-term assets and accounts payable and accrued liabilities, respectively. The credit agreement also imposes certain other customary restrictions and covenants as well as certain milestones we must meet in order to draw down the full amount. Any non-tax cash distributions from Savoy are required to be applied toward the debt. The term loan requires quarterly payments with annual amortization at 10%, 15%, 15%, 20%, and 20% with a balloon at maturity. The credit agreement matures on August 29, 2019, but we have the right to prepay the loan at any time without penalty. 32 ( 4) 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: Expected amount Change in Indiana rate State income taxes, net of federal benefit Percentage depletion Stock-based compensation Captive insurance Other 2014 2013 3,745 $ (1,407 ) 186 (1,996 ) 343 (419 ) 30 482 $ 10,359 877 (3,826 ) (419 ) 184 7,175 $ $ The deferred tax assets and liabilities resulting from temporary differences between book and tax basis are comprised of the following at December 31: Long-term deferred tax assets: Stock-based compensation Investment in Savoy Oil and gas properties Alternative minimum tax credit Net long-term deferred tax assets Long-term deferred tax liabilities: Coal properties Net deferred tax liability 2014 2013 $ 347 $ 1,227 (2,234 ) 4,043 3,383 372 1,885 913 3,170 $ (44,964 ) 41,581 $ (46,474 ) 43,304 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. During 2012 the IRS completed an examination of our 2009 and 2010 federal tax returns and there were no significant adjustments. During 2012 the State of Indiana completed their examination of our 2008-2010 returns and no adjustments were proposed. We believe that our income tax filing positions and deductions will be sustained on audit and do not anticipate any adjustments that will result in a material change to our consolidated financial position. (5) Stock Compensation Plans Restricted Stock Units (RSUs) At December 31, 2014 we had 1,042,000 RSUs outstanding and 1,257,900 available for future issuance. The outstanding RSUs have a value of $13 million based on the March 4, 2015 closing stock price of $12.67. On February 1, 2014 we granted 920,000 RSUs to key employees of which 720,000 vest equally over four years and 200,000 over two years. Our stock price on grant date was $7.66. On April 1, 2014, we granted 171,000 RSUs and our stock price was $8.54. On September 2, 2014 we granted 99,000 RSUs and our stock price was $13.56. On three other occasions in 2014, we granted a total of 5,500 RSUs; our stock price on those dates ranged from $11.39 to $14.06. All RSUs granted in 2014, other than those on February 1, cliff vest over three years. In July 2013, we granted 4,000 RSUs with cliff vesting of three years; our stock price on grant date was $8.14. We expect 407,000 RSUs to vest during 2015 under our current vesting schedule. 33 During 2014 and 2013, there were 310,000 and 315,500 RSUs that vested, respectively. On the vesting dates the shares had a value of $3.1 million for 2014 and $2.3 million for 2013. Under our RSU plan participants are allowed to relinquish shares to pay for their required minimum statutory income taxes. Stock-based compensation expense for 2014 was $3.2 million and for 2013 was $2.2 million. For 2015, based on existing RSUs outstanding, stock-based compensation expense will be $3.3 million. Stock Bonus Plan Our stock bonus plan was authorized in late 2009 with 250,000 shares. Currently, we have about 86,000 shares left in such plan. (6) Employee Benefits We have no defined benefit pension plans or any post-retirement benefit plans. We offer our employees a 401(k) Plan, where we match 100% of the first 4% that an employee contributes, a bonus plan based on meeting certain production levels and a discretionary Deferred Bonus Plan for certain key employees. We also offer health benefits to all employees and their families. We have 3,063 participants in our employee health plan. The plan does not cover dental, vision, short-term or long-term disability. These coverages are available on a voluntary basis. We bear some of the risk of our employee health plans. Our health claims are capped at $110,000 per person with a maximum annual exposure of $15 million not including premiums. Our 2014 expense for the 401(k) matching was $815,000 and our expense for health benefits was $8.1 million. Our 2013 expense for the 401(k) matching was $700,000 and our expense for health benefits was $4.1 million. The 2014 expense for the Deferred Bonus Plan was $406,000 and the 2013 expense was $467,000. The expense for the production bonus plan was $373,000 for 2014 and $582,000 for 2013. Our mine employees are also covered by workers’ compensation and such costs for 2014 and 2013 were about $2.8 million and $1.3 million, respectively. Workers’ compensation is a no-fault system by which individuals who sustain work related injuries or occupational diseases are compensated. Benefits and coverage are mandated by each state which includes disability ratings, medical claims, rehabilitation services, and death and survivor benefits. Our operations are protected from these perils through insurance policies. Our maximum annual exposure is limited to $1 million per occurrence with a $4 million aggregate deductible. Based on discussions and representations from our insurance carrier we believe that our reserve for our workers’ compensation benefits is adequate. We have a safety conscious workforce and our worker’s compensation injuries have been minimal. (7) Other Long-Term Assets and Other Income Long-term assets: Advance coal royalties Deferred financing costs, net Marketable equity securities available for sale, at fair value (restricted)* Ohio River Terminal (see Note 9) Other *Held by Sunrise Indemnity, Inc., our wholly-owned captive insurance company. Other income: MSHA reimbursements** Coal storage fees Miscellaneous **See “MSHA Reimbursements” in the MD&A section for a discussion of these amounts. 34 2014 2013 5,496 $ 6,507 2,249 2,653 1,944 18,849 $ 4,693 1,195 3,889 2,836 2,769 15,382 $ 383 1,366 1,749 $ 3,672 1,238 768 5,678 $ $ $ $ (8) Self Insurance In late August 2010 we decided to terminate the property insurance on our underground mining equipment. Such equipment is allocated among 11 mining units at our three underground mines. These units are spread out over 30 miles in 11 different locations at the three mines. The historical cost of such equipment is about $246 million. (9) Ohio River Terminal On May 31, 2013 we purchased for $2.8 million a multi-commodity truck/barge terminal. Over 17 acres of secured area is available. The terminal is at mile point 743.8 on the Indiana bank of the Ohio River near the William Natcher Bridge between Rockport and Grandview, Indiana. Currently the dock will handle third party commodities. In the long term, we plan to ship coal through the dock. The terminal is in close proximity to the NS railroad, the CSX Railroad, and American Electric Power's Rockport generating power plant. (10) Liability Extinguishment During the 2013 second quarter we concluded that an approximate $4.3 million liability we recorded during 2006 upon the purchase of Sunrise Coal relating to a terminated coal contract was no longer required. The amount had no effect on cash flows. (11) Net Income per Share We compute net income per share using the two-class method, which is an allocation formula that determines net income per share for common stock and participating securities, which for us are our outstanding RSUs. Outstanding RSUs of 1,042,000 have been excluded because the impact would be anti-dilutive. The following table sets forth the computation of net income per share for 2014. The adjustments for 2013 were not significant (in thousands, except per share amounts): Numerator: Net income Less earnings allocated to RSUs Net income Denominator: Weighted average number of common shares outstanding Potential dilutive shares Weighted average number of diluted shares outstanding Net income per share: Basic Diluted 35 $ $ 2014 10,219 (375 ) 9,844 28,776 0 28,776 $ $ 0.34 0.34 (12) 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. Our marketable securities are 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. The fair values of our swaps were estimated using discounted cash flow calculations based upon forward interest-rate yield curves. 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. The purchase price allocation for the acquisition of VFI was determined using Level 3 measurements. Mobile mining equipment was valued via the market approach. Fixed equipment and mine development was valued via the cost approach using direct and indirect (trending) methods. The mineral reserves and ARO were valued via a discounted future cash flow model. (13) Equity Investment in Sunrise Energy We own a 50% interest in Sunrise Energy, LLC, which owns gas reserves and gathering equipment with plans to develop and operate such reserves. Sunrise Energy also plans to develop and explore for coal-bed methane gas reserves on or near our underground coal reserves. They use the successful efforts method of accounting. We account for our interest using the equity method of accounting. Below (in thousands) to the 100% is a condensed balance sheet at December 31, for both years and a condensed statement of operations for both years. Sunrise Energy’s proved oil and gas reserves are not material. Condensed Balance Sheet Current assets Oil and gas properties, net Total liabilities Members’ capital Revenue Expenses Net income 2014 2013 3,580 $ 7,130 10,710 $ 1,080 $ 9,630 10,710 $ 3,109 6,781 9,890 756 9,134 9,890 2014 2013 3,203 $ (2,707 ) 496 $ 3,399 (2,141 ) 1,258 $ $ $ $ $ $ Condensed Statement of Operations 36 (14) Equity Investment in Savoy We currently own a 40% interest in Savoy Energy, L.P., a private company engaged in the oil and gas business primarily in the state of Michigan. Savoy uses the successful efforts method of accounting. Our 45% ownership was decreased to 40% on October 1, 2014 due to the exercise of options by Savoy’s management. We account for our interest using the equity method of accounting. Below (in thousands) to the 100% is a condensed balance sheet at December 31, for both years and a condensed statement of operations for both years. Condensed Balance Sheet Current assets Oil and gas properties, net Other Total liabilities Partners' capital Revenue Expenses Net income Condensed Statement of Operations 2014 2013 14,863 $ 27,549 852 43,264 $ 10,079 $ 33,185 43,264 $ 29,182 25,408 260 54,850 16,447 38,403 54,850 2014 2013 41,583 $ (29,354 ) 12,229 $ 42,248 (29,322 ) 12,926 $ $ $ $ $ $ In 2014, Savoy engaged Energy Spectrum Advisors Inc. (ESA) to market its Trenton-Black River oil properties located in southeast Michigan. No acceptable offers were received. Marketing efforts are on hold until oil prices recover Savoy made a $12 million cash distribution in early October 2014; our share was $4.9 million; such amount was applied toward our bank debt as required under the new credit agreement. 37 Unaudited Oil and Gas Reserve Quantity and Value Information (in thousands) The data below is shown proportionate to our 40% (45% in 2013) ownership of Savoy. Costs incurred are as follows: Unproved property acquisition Development Exploration Total Change in proved reserves: January 1, 2013 Extensions and discoveries Production Revisions to previous estimates December 31, 2013 Extensions and discoveries Production Revisions to previous estimates Change in ownership from 45% to 40% December 31, 2014 Proved developed reserves included above: December 31, 2013 December 31, 2014 Proved undeveloped reserves (PUDs) included above: December 31, 2013 December 31, 2014 FOR INFORMATION PURPOSES ONLY 2014 2013 $ $ 899 $ 1,224 5,130 7,253 $ 1,287 858 7,061 9,206 Oil (Bbls) NGLs (Bbls) Natgas (Mcf) 700 898 (153 ) 24 1,469 262 (143 ) (840 ) (73 ) 675 746 467 723 208 29 58 (11 ) 23 99 14 (9 ) (60 ) (5 ) 39 60 30 39 9 1,108 442 (96 ) (153 ) 1,301 253 (83 ) (956 ) (65 ) 450 450 292 851 158 December 31, 2014 based on current and future NYMEX strip prices Future cash inflows: Oil NGLs Natgas Total cash inflows Future production costs Future development costs Future income tax (none since Savoy is a pass-through entity for income tax purposes) Future net cash flows 10% annual discount for estimated timing of cash flows Discounted future net cash flows Proved Developed PUDs Total Proved $ 24,768 $ 785 915 26,468 (9,462 ) (58 ) 12,239 $ 252 683 13,174 (3,398 ) (1,800 ) 37,007 1,037 1,598 39,642 (12,860 ) (1,858 ) 16,948 (3,608 ) 13,340 $ 7,976 (2,336 ) 5,640 $ 24,924 (5,944 ) 18,980 $ 38 December 31, 2014 based on SEC first-of-month average prices Future cash inflows: Proved Developed PUDs Total Proved Oil NGLs Natgas $ Total cash inflows Future production costs Future development costs Future income tax (none because Savoy is a pass-through entity for income tax 41,660 $ 1,256 1,203 44,119 (12,886 ) (60 ) 18,530 $ 368 721 19,619 (3,749 ) (1,790 ) 60,190 1,624 1,924 63,738 (16,635 ) (1,850 ) purposes) Future net cash flows 10% annual discount for estimated timing of cash flows Standardized measure of discounted future net cash flows December 31, 2013 based on SEC first-of-month average prices Future cash inflows: Oil NGLs Natgas Total cash inflows Future production costs Future development costs Future income tax (none because Savoy is a pass-through entity for income tax purposes) Future net cash flows 10% annual discount for estimated timing of cash flows Standardized measure of discounted future net cash flows 31,173 (7,125 ) 24,048 $ 14,080 (4,028 ) 10,052 $ 45,253 (11,153 ) 34,100 $ Proved Developed PUDs Total Proved $ 70,582 $ 2,551 1,365 74,498 (12,213 ) 70,662 $ 1,669 976 73,307 (12,233 ) (3,073 ) 141,244 4,220 2,341 147,805 (24,446 ) (3,073 ) 62,285 (14,375 ) 47,910 $ 58,001 (15,111 ) 42,890 $ 120,286 (29,486 ) 90,800 $ 2014 2013 Beginning of year Sales, net of production costs Net changes in prices and production costs Extensions and discoveries Revisions of previous quantity estimates Change in production timing and other Change in ownership from 45% to 40% Accretion of discount End of year Average wellhead prices based on SEC average prices: Oil (per Bbl) NGLs (per Bbl) Natgas (per Mcf) Average wellhead prices based on NYMEX strip prices: Oil (per Bbl) NGLs (per Bbl) Natgas (per Mcf) 39 35,300 (12,600 ) 1,600 57,200 2,100 3,700 3,500 90,800 95 42 3.04 $ $ $ 90,800 $ (11,000 ) (5,700 ) 13,300 (61,000 ) 3,100 (4,500 ) 9,100 34,100 $ 89 $ 41 4.27 59 28 3.94 The 2014 reserve estimates shown above have been independently evaluated by Netherland, Sewell & Associates, Inc. (NSAI), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical person primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein is Mr. G. Lance Binder. Mr. Binder, a Licensed Professional Engineer in the State of Texas (No. 61794), has been practicing consulting petroleum engineering at NSAI since 1983 and has over 5 years of prior industry experience. He graduated from Purdue University in 1978 with a Bachelor of Science Degree in Chemical Engineering. He meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering evaluations as well as applying SEC and other industry reserves definitions and guidelines. Brock Engineering, LLC, an independent petroleum engineering firm, estimated our proved reserves as of December 31, 2013. Differences in the professional opinions of the two engineering firms, plus the fact that estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors are the primary reasons for the 2014 downward revision. ITEM 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. Not applicable. ITEM 9A. CONTROLS AND PROCEDURES. Disclosure Controls We maintain a system of disclosure controls and procedures that are designed for the purposes of ensuring that information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to our CEO and CFO as appropriate to allow timely decisions regarding required disclosure. As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our CEO and CFO of the effectiveness of the design and operation of our disclosure controls and procedures. Based upon that evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective for the purposes discussed above. Internal Control Over Financial Reporting (ICFR ) Our management, including our Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate ICFR. Our ICFR is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles in the United States. Because of its inherent limitations, ICFR may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives. Management evaluated the effectiveness of our ICFR based on the framework in “Internal Control – Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in 2013. Our management evaluated, with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our ICFR as of December 31, 2014. Based on that evaluation, our management concluded that our ICFR was effective at December 31, 2014. As allowed, this evaluation excludes the operations of Vectren Fuels due to the timing of the acquisition. Revenue related to Vectren Fuels were 40% of total revenue for the year ended December 31, 2014. EKS&H LLLP has audited and reported on our financial statements and our ICFR as of December 31, 2014. Their report is contained in this Form 10-K. 40 Changes in internal control over financial reporting Other than the hiring of additional accounting staff relating to the VFI acquisition that allowed us to further segregate certain accounting duties, there were no significant changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2014, that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting. 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, 2013. There has been no change in our internal control over financial reporting during the quarter ended December 31, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. This annual report does not include an attestation report from EKSH our auditors, regarding ICFR. Our report was not subject to attestation by EKSH pursuant to existing rules of the SEC that permits us to provide only our report in this annual report. ITEM 9B. OTHER INFORMATION On December 15, 2014, our Board of Directors and Compensation Committee met to determine bonus compensation to our named executive officers. The Board determined that the purchase of all common stock of Vectren Fuels, Inc. effective August 29, 2014 met the goals set for success. The Compensation Committee set three performance criteria for success including consummating the purchase of Vectren Fuels, Inc. at a reasonable fair market value, structuring bank debt using an administrative agent to structure a new debt vehicle and executing on an integration plan that included the successful transition of skilled and motivated workers. The Committee approved bonuses in the aggregate amount of $1.2MM to the NEOs and to a certain employee for 2014. On December 20, 2014, these payments were made as follows: Mr. Bilsland $430,000; Mr. Martin $214,000; Mr. Stabio $198,000; Mr. Bishop $100,000 and $214,000 to the employee. If certain performance goals (EBITDA of $100 million) are met in 2015, up to twice those amounts could be paid. PART III The information required for Items 10-14 are hereby incorporated by reference to that certain information in our Information Statement to be filed with the SEC during March 2015. ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE. ITEM 11. EXECUTIVE COMPENSATION ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES. 41 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 3.2 10.1 10.2 10.3 10.4 10.5 10.6 10.7 10.8 10.9 10.10 10.11 10.12 10.13 10.14 10.15 14 21.1 23.1 23.2 23.3 31 32 95 99 101 Second Restated Articles of Incorporation of Hallador Energy Company effective December 24, 2009. (1) By-laws of Hallador Energy Company, effective December 24, 2009 (1) Purchase and Sale Agreement dated December 31, 2005 between Hallador Petroleum Company, as Purchaser and Yorktown Energy Partners II, L.P., as Seller relating to the purchase and sale of limited partnership interests in Savoy Energy Limited Partnership (2) Letter of Intent dated January 5, 2006 between Hallador Petroleum Company and Sunrise Coal, LLC (3) Reimbursement Agreement, dated April 19, 2006, between Hallador Petroleum Company and Sunrise Coal, LLC (5) Membership Interest Purchase Agreement dated July 31, 2006 by and between Hallador Petroleum Company and Sunrise Coal, LLC. (6) Purchase and Sale Agreement dated effective as of October 5, 2007 between Hallador Petroleum Company, as Purchaser and Savoy Energy Limited Partnership, as Seller (7) Hallador Petroleum Company 2008 Restricted Stock Unit Plan. (8)* 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 (9) 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 (10) Form of Purchase and Sale Agreement dated September 16, 2009 (11) Form of Subscription Agreement dated September 15, 2009 (11) Form of Hallador Petroleum Company Restricted Stock Unit Issuance Agreement. (11)* 2009 Stock Bonus Plan(12)* $165,000,000 Revolving Credit Facility (13) Stock Purchase Agreement (Vectren Fuels) (14) Second Amended Restated Credit Agreement – August 29, 2014 (15) Code Of Ethics For Senior Financial Officers. (4)* List of Subsidiaries (16) Consent of EKS&H LLLP (16) Consent of Brock Engineering, LLC(16) Consent of Netherland, Sewell & Associates, Inc. (16) SOX 302 Certifications (16) SOX 906 Certification (16) Mine Safety Disclosure (16) 2014 SEC Reserve Report by Netherland, Sewall & Associates(16) Interactive data files. (1) IBR to Form 8-K dated December 31, 2009. (2) IBR to Form 8-K dated January 3, 2006. (3) IBR to Form 8-K dated January 6, 2006. (4) IBR to the 2005 Form 10-KSB. (5) IBR to Form 8-K dated April 25, 2006. (6) IBR to Form 8-K dated August 1, 2006. (7) IBR to Form 10-KSB dated December 31, 2007. (8) IBR to March 31, 2007 Form 10-Q. *Management Agreements (9) IBR to Form 8-K dated July 24, 2008. (10) IBR to Form 8-K dated December 12, 2008. (11) IBR to Form 8-K dated September 18, 2009. (12) IBR to Form S-8 dated December 1, 2009. (13) IBR to Form 8-K dated October 18, 2012 (14) IBR to Form 8-K dated July 8, 2014 (15) IBR to Form 10-Q dated November 10, 2014 (16) Filed herewith. 42 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. Date: March 6, 2015 HALLADOR ENERGY COMPANY /s/W. ANDERSON BISHOP W. Anderson Bishop, CFO and CAO Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. /s/DAVID HARDIE David Hardie /s/VICTOR P. STABIO Victor P. Stabio /s/BRYAN LAWRENCE Bryan Lawrence /s/BRENT BILSLAND Brent Bilsland /s/JOHN VAN HEUVELEN John Van Heuvelen Director March 6, 2015 Chairman March 6, 2015 Director March 6, 2015 President, CEO and Director March 6, 2015 Director March 6, 2015 43 Exhibit 21.1 List of Subsidiaries Oaktown Fuels Mine No. 1, LLC Oaktown Fuels Mine No. 2, LLC Prosperity Mine, LLC Savoy Energy, L.P. SFI Coal Sales, LLC Summit Terminal, LLC Sunrise Coal LLC Sunrise Energy, LLC Sunrise Indemnity, Inc. Sunrise Land Company, LLC Sycamore Coal, Inc. EXHIBIT 23.1 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (No. 333-163431 and No. 333- 171778) of Hallador Energy Company, of our report dated March 5, 2015, on the consolidated financial statements of Hallador Energy Company which appears in this Form 10-K for the year ended December 31, 2014. /s/ EKS&H LLLP March 5, 2015 Denver, Colorado EXHIBIT 23.2 CONSENT OF INDEPENDENT PETROLEUM ENGINEERS We hereby consent to the reference to our firm and to the information regarding our reserve estimates of Savoy Energy, L. P. as of December 31, 2013 included in Hallador Energy Company’s Form 10-K for the year ended December 31, 2014. We hereby further consent to the incorporation by reference in the two Registration Statements on Form S-8 (No. 333-163431 and No. 333-171778) of such information. Brock Engineering, LLC /s/Timothy J Brock Timothy J Brock, PE Its President Traverse City, Michigan March 5, 2015 Exhibit 23.3 CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS We hereby consent to (i) the use of the name Netherland, Sewell, & Associates, Inc., the reference to our reserve report dated February 10, 2015 for Savoy Energy, L.P. of which Hallador Energy Company (the “Company”) owns a 40% equity interest, and the use of information contained therein in the Company’s 2014 Form 10-K to be filed on or about March 6, 2015, and (ii) inclusion of our summary report dated February 10, 2015, included in such Form 10-K, as Exhibit 99. We hereby further consent to the incorporation by reference in the two Registration Statements on Form S-8 (file # 333-163431 and # 333-171778) of such information. NETHERLAND, SEWELL & ASSOCIATES, INC. By: /s/ C. H. (Scott) Rees, III C. H. (Scott) Rees III, P. E. Chairman and CEO Dallas, Texas March 5, 2015 Exhibit 31.1 CERTIFICATION I, Brent K. Bilsland, certify that: 1. I have reviewed this annual report on Form 10-K of Hallador Energy Company; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. March 6, 2015 /s/ Brent K. Bilsland Brent K. Bilsland, President and CEO Exhibit 31.2 CERTIFICATION I, W. Anderson Bishop, certify that: 1. I have reviewed this annual report on Form 10-K of Hallador Energy Company; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. March 6, 2015 /s/ W. Anderson Bishop W. Anderson Bishop, CFO Exhibit 32 CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Hallador Energy Company (the "Company"), on Form 10-K for the period ended December 31, 2014, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned, in the capacities and date indicated below, each hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge: (1) (2) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. March 6, 2015 By: /s/Brent K. Bilsland Brent K. Bilsland, President and CEO /s/W. Anderson Bishop W. Anderson Bishop, CFO Exhibit 95 Exhibit 95 - Mine Safety Disclosure Our principles are safety, honesty, and compliance. We firmly believe that these values compose a dedicated workforce and with that, come high production. The core to this is our strong training programs that include accident prevention, workplace inspection and examination, emergency response, and compliance. We work with the Federal and State regulatory agencies to help eliminate safety and health hazards from our workplace and increase safety and compliance awareness throughout the mining industry. Sunrise has not had a fatality since its establishment in 2005. Sunrise is regulated by the MSHA under the Federal Mine Safety and Health Act of 1977 (“Mine Act”). MSHA inspects our mine on a regular basis and issues various citations and orders when it believes a violation has occurred under the Mine Act. We present information below regarding certain violations which MSHA has issued with respect to our mine. While assessing this information please consider that the number and cost of violations will vary depending on the MSHA inspector and can be contested and appealed, and in that process, are often reduced in severity and amount, and are sometimes dismissed. We are currently contesting no MSHA citations. Sunrise has not been issued written notice from MSHA of a pattern of, or the potential to have a pattern of, violations of mandatory health or safety standards that are of such a nature as could significantly and substantially cause and effect health or safety standards under section 104(e) of the Mine Act. The table that follows outlines citations and orders issued to us by MSHA during the first nine months of 2014. The citations and orders outlined below may differ from MSHA`s data retrieval system due to timing, special assessed citations, and other factors. Definitions: Section 104(a) Significant and Substantial Citations “S&S”: An alleged violation of a mining safety or health standard or regulation where there exists a reasonable likelihood that the hazard outlined will result in an injury or illness of a serious nature. Section 104(b) Orders: Failure to abate a 104(a) citation within the period of time prescribed by MSHA. The result of which is an order of immediate withdraw of non-essential persons from the affected area until MSHA determines the violation has been corrected. Section 104(d) Citations and Orders: An alleged unwarrantable failure to comply with mandatory health and safety standards. Section 107(a) Orders: An order of withdraw for situations where MSHA has determined that an imminent danger exists. Section 110(b) (2) Violations: An alleged flagrant violation issued by MSHA under section 110(b) (2) of the Mine Act. Pattern or Potential Pattern of Violations: A pattern of violations of mandatory health or safety standards that are of such a nature as could have significantly and substantially contributed to the cause and effect of coal mine health or safety hazards under section 104(e) of the Mine Act or a potential to have such a pattern. Contest of Citations, Orders, or Proposed Penalties: A contest proceeding may be filed with the Commission by the operator or miners/miners representative to challenge the issuance or penalty of a citation or order issued by MSHA. Carlisle Mine January February March April May June July August September October November December Totals Ace in the Hole Mine January February March April May June July August September October November December Totals Section Section Proposed Section Section 110(b)(2) 104(a) 107(a) Violations Assessments Citations Citations Citations/Orders Orders (In thousands) Section 104(d) 104(b) MSHA 5.00 1.00 3.00 7.00 5.00 2.00 4.00 3.00 16.00 5.00 6.00 5.00 62.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 $ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 $ 5.40 2.40 8.00 16.00 9.10 6.90 7.60 6.60 39.00 11.10 8.40 13.60 134.10 Section Section Proposed Section Section 110(b)(2) 104(a) 107(a) Violations Assessments Citations Citations Citations/Orders Orders (In thousands) Section 104(d) 104(b) MSHA 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 1.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 1.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 $ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 $ 0.00 0.00 28.90 0.00 0.00 0.10 0.00 0.00 0.00 0.00 0.00 0.00 29.00 Carlisle Preparation Plant January February March April May June July August September October November December Totals Section Section Proposed Section Section 110(b)(2) 104(a) 107(a) Violations Assessments Citations Citations Citations/Orders Orders (In thousands) Section 104(d) 104(b) MSHA 0.00 0.00 0.00 0.00 0.00 0.00 0.00 1.00 0.00 0.00 0.00 0.00 1.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 $ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 $ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 1.40 0.00 0.00 0.00 0.00 1.40 Oaktown Fuels No. 1 Sunrise Coal, LLC took operational control on August 30, 2014 Section Section Proposed Section Section 110(b)(2) 104(a) 107(a) Violations Assessments Citations Citations Citations/Orders Orders (In thousands) Section 104(d) 104(b) MSHA January February March April May June July August September October November December Totals 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 4.00 7.00 3.00 0.00 14.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 $ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 $ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 4.50 19.60 5.50 0.70 30.30 Oaktown Fuels No. 2 Sunrise Coal, LLC took operational control on August 30, 2014 Section Section Proposed Section Section 110(b)(2) 104(a) 107(a) Violations Assessments Citations Citations Citations/Orders Orders (In thousands) Section 104(d) 104(b) MSHA January February March April May June July August September October November December Totals 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 6.00 5.00 1.00 0.00 12.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 $ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 $ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 4.75 10.80 1.40 0.10 17.05 Oaktown Fuels Preparation Plant Sunrise Coal, LLC took operational control on August 30, 2014 Section Section Proposed Section Section 110(b)(2) 104(a) 107(a) Violations Assessments Citations Citations Citations/Orders Orders (In thousands) Section 104(d) 104(b) MSHA January February March April May June July August September October November December Totals 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2.00 0.00 0.00 0.00 2.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 $ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 $ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.70 0.00 0.00 0.00 0.70 Prosperity Mine Sunrise Coal, LLC took operational control on August 30, 2014 Section Section Proposed Section Section 110(b)(2) 104(a) 107(a) Violations Assessments Citations Citations Citations/Orders Orders (In thousands) Section 104(d) 104(b) MSHA January February March April May June July August September October November December Totals 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 1.00 0.00 0.00 1.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 $ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 $ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.60 14.85 0.10 0.20 15.75 Exhibit 99 February 10, 2015 Mr. W. Anderson Bishop Hallador Energy Company 1660 Lincoln Street, Suite 2700 Denver, Colorado 80264 Dear Mr. Bishop: In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2014, to the Savoy Energy, L.P. (Savoy) interest in certain oil and gas properties located in Michigan and Oklahoma. We completed our evaluation on or about the date of this letter. It is our understanding that Hallador Energy Company (Hallador) owns a 40 percent equity interest in Savoy and that the 40 percent share of the proved reserves estimated in this report constitutes all of the proved reserves owned by Hallador. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, except that future income taxes are excluded for all properties and, as requested, per-well overhead expenses are excluded for the operated properties. Definitions are presented immediately following this letter. This report has been prepared for Hallador's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose. We estimate the net reserves and future net revenue to the Savoy interest in these properties, as of December 31, 2014, to be: Category (MBBL) (MBBL) (MMCF) Net Reserves NGL Gas Oil Future Net Revenue (M$) Present Worth at 10% Total Proved Developed Producing Proved Developed Non-Producing Proved Undeveloped 914.3 253.7 520.2 55.0 20.6 22.5 648.5 59,012.1 81.0 18,911.6 394.4 35,202.1 45,545.0 14,636.0 25,130.7 Total Proved 1,688.2 98.1 1,123.9 113,125.8 85,311.7 The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases. The table following the definitions sets forth our estimates of net reserves and future net revenue, by reserves category, to the Savoy interest for each property group. The estimates shown in this report are for proved reserves. As requested, probable and possible reserves that exist for these properties have not been included. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk. Gross revenue is Savoy's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Savoy's share of production taxes, capital costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties. Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2014. For oil and NGL volumes, the average West Texas Intermediate posted price of $91.48 per barrel is adjusted by lease for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $4.350 per MMBTU is adjusted by lease for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $89.14 per barrel of oil, $41.40 per barrel of NGL, and $4.279 per MCF of gas. Operating costs used in this report are based on operating expense records of Savoy. For the nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. As requested, operating costs for the operated properties include only direct lease- and field-level costs. For all properties, headquarters general and administrative overhead expenses of Savoy are not included. Operating costs are not escalated for inflation. Capital costs used in this report were provided by Savoy and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Capital costs are not escalated for inflation. As requested, our estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties. For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability. We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Savoy interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Savoy receiving its net revenue interest share of estimated future gross production. The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Savoy, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report. For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for behind-pipe zones, undeveloped locations, and producing wells that lack sufficient production history upon which performance- related estimates of reserves can be based; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment. The data used in our estimates were obtained from Savoy, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical person primarily responsible for preparing the estimates presented herein meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. G. Lance Binder, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 1983 and has over 5 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis. Sincerely, NETHERLAND, SEWELL & ASSOCIATES, INC. Texas Registered Engineering Firm F-2699 By: /s/ C.H. (Scott) Rees III C.H. (Scott) Rees III, P.E. Chairman and Chief Executive Officer By: /s/ G. Lance Binder G. Lance Binder, P.E. 61794 Executive Vice President Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document. DEFINITIONS OF OIL AND GAS RESERVES The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations. (1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties. (2) Analogous reservoir . Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest: (i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) Same environment of deposition; (iii) Similar geological structure; and (iv) Same drive mechanism. Instruction to paragraph (a)(2) : Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest. (3) Bitumen . Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons. (4) Condensate . Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature. (5) Deterministic estimate . The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure. (6) Developed oil and gas reserves . Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Supplemental definitions from the 2007 Petroleum Resources Management System: Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation. Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. (7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:  (i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves. (ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly. (iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems. (iv) Provide improved recovery systems. (8) Development project . A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project. (9) Development well . A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. (10) Economically producible . The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section. (11) Estimated ultimate recovery (EUR) . Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date. (12) Exploration costs . Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are: (i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs. (ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records. (iii) Dry hole contributions and bottom hole contributions. (iv) Costs of drilling and equipping exploratory wells. (v) Costs of drilling exploratory-type stratigraphic test wells. (13) Exploratory well . An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section. (14) Extension well . An extension well is a well drilled to extend the limits of a known reservoir. (15) Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc. (16) Oil and gas producing activities. (i) Oil and gas producing activities include: (A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations; (B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;  (C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as: (1) Lifting the oil and gas to the surface; and (2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and (D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction. Instruction 1 to paragraph (a)(16)(i) : The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as: a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a b. refinery, or a marine terminal; and In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas. Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered. (ii) Oil and gas producing activities do not include: (A) Transporting, refining, or marketing oil and gas; (B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production; (C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or (D) Production of geothermal steam. (17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. (i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. (ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. (iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. (iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. (v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. (vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations. (18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.  (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. (ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. (iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. (iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. (19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence. (20) Production costs. (i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are: (A) Costs of labor to operate the wells and related equipment and facilities. (B) Repairs and maintenance. (C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities. (D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities. (E) Severance taxes. (ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above. (21) Proved area. The part of a property to which proved reserves have been specifically attributed. (22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. (23) Proved properties. Properties with proved reserves. (24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease. (25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. (26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project. Note to paragraph (a)(26) : Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations). Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas: 932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year: a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B) b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7). The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes. 932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B: a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end. b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs. c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves. d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.  e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves. f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount. (27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. (28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations. (29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion. (30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area. (31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. From the SEC's Compliance and Disclosure Interpretations (October 26, 2009): Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule. Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following: (cid:5) The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities); (cid:5) The company's historical record at completing development of comparable long-term projects; (cid:5) The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities; (cid:5) The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and (cid:5) The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority). (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty. (32) Unproved properties. Properties with no proved reserves. 

Continue reading text version or see original annual report in PDF format above