Item 1A.
RISK FACTORS
Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report, actually occur, our business, financial condition or results of operations could suffer. Additional risks not presently known to us or which we currently consider immaterial also may adversely affect our company.
Risks Related to Our Business
Natural gas, NGLs and oil prices have been volatile and have declined from recent historical highs. If commodity prices remain depressed for a lengthy period of time or experience a further substantial or extended decline, our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments may be adversely affected.
The prices we receive for our natural gas, NGLs and oil production heavily influence our revenue, operating results, profitability, access to capital, future rate of growth and carrying value of our properties. Natural gas, NGLs and oil are commodities, and therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities markets have been volatile, and these markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include, but are not limited to, the following:
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worldwide and regional economic conditions impacting the global supply of and demand for natural gas, NGLs and oil;
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the price and quantity of imports of foreign natural gas, including liquefied natural gas, foreign oil and refined products;
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the price and quantity of exported domestic crude oil, natural gas, including liquefied natural gas, NGLs and refined products;
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political conditions in or affecting other producing countries, including conflicts in the Middle East, Africa, South America and Russia;
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the level of global exploration and production;
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the level of global inventories;
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changes in the level of consumer and industrial demand, including impacts from global or national health epidemics and concerns, such as the recent coronavirus (COVID-19);
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prevailing prices on local price indexes in the areas in which we operate and expectations about future commodity prices;
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the actions of the Organization of the Petroleum Exporting Countries;
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the proximity, capacity, cost and availability of gathering and transportation facilities, and other factors that result in differentials to benchmark prices;
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the cost of exploring for, developing, producing and transporting reserves;
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speculative trading in natural gas and crude oil derivative contracts;
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risks associated with operating drilling rigs;
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increased end-user conservation or conversion of alternative fuels;
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the price and availability of competitors’ supplies of natural gas, NGLs, oil and alternative fuels;
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localized and global supply and demand fundamentals and transportation availability;
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adverse or severe weather conditions and other natural disasters;
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technological advances affecting energy consumption and production; and
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domestic, local and foreign governmental regulation and taxes.
In addition, substantially all of our natural gas production and oil production is sold to purchasers under contracts with market-based prices based on NYMEX Henry Hub prices and WTI prices, respectively. The actual prices realized from the sale of natural gas and oil differ from the quoted NYMEX Henry Hub and WTI prices as a result of location differentials. Location differentials to NYMEX Henry Hub and WTI prices, also known as basis differential, result from variances in regional natural gas and oil prices as compared to NYMEX Henry Hub and WTI prices due to regional supply and demand factors. We have experienced, and expect to continue to experience, differentials to NYMEX Henry Hub and WTI prices, which may be material and could reduce the price we receive for these products relative to these benchmarks.
Lower commodity prices and negative increases in our differentials have reduced, and we expect will continue to reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, or at all, which could lead to a decline in our reserves as existing reserves are depleted. Lower commodity prices and negative differentials have also caused a significant portion of our development and exploration projects to become uneconomic, which may result in our having to make significant downward adjustments to our reserves. As a result, if commodity prices continue to remain depressed for a lengthy period of time or experience a further substantial or extended decline, or if our negative differentials increase, our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures may be materially adversely affected.
Commodity prices have declined substantially from historic highs and may remain depressed for the foreseeable future. If commodity prices continue to remain depressed, we may be required to write down the value of our oil and natural gas properties, some of our undeveloped locations may no longer be economically viable and the value of our estimated proved reserves could be reduced materially.
During the eight years prior to December 31, 2019, natural gas prices at Henry Hub have ranged from a high of $8.15 per MMBtu in 2014 to a low of $1.49 per MMBtu in 2016. On December 31, 2019, the Henry Hub spot market price of natural gas was $2.09 per MMBtu. The reduction in prices has been caused by many factors, including increases in natural gas production and reserves from unconventional (shale) reservoirs, without an offsetting increase in demand. In addition, oil prices have declined significantly since the second half of 2014. The price of WTI crude oil was $61.14 per barrel on December 31, 2019, which is a significant decline from $106.07 per barrel on June 30, 2014. This environment could cause the commodity prices for oil and natural gas to remain at currently depressed levels or to fall to lower levels. If commodity prices remain depressed for lengthy periods, we may be required to write down the value of our oil and natural gas properties, and some of our undeveloped locations may no longer be economically viable. For example, for the year ended December 31, 2019, we recorded an impairment charge on certain oil and gas properties of $45.8 million for unproved properties, primarily attributable to lower commodity prices, and we have recorded impairment charges in prior years for similar reasons. In addition, sustained low commodity prices will negatively impact the value of our estimated proved reserves, which will negatively affect the borrowing base under our revolving credit facility and reduce the amounts of cash we would otherwise have available to pay expenses and service any indebtedness that we may incur. In such a case, we may be required to sell assets or raise capital by issuing additional debt or equity in order to pay expenses and service indebtedness. Furthermore, the value of our assets, if sold, may not be sufficient to pay our expenses or service our indebtedness.
If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write-downs of the carrying values of our properties.
Accounting rules require that we periodically review the carrying value of our properties for possible impairment. For example, for the year ended December 31, 2019, we recorded an impairment charge on certain oil and gas properties of $45.8 million for unproved properties, primarily attributable to lower commodity prices, and we have recorded impairment charges in prior years for similar reasons. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to further write down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. We may incur additional impairment charges in
the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.
If commodity prices do not improve or worsen or if we are unable to increase our liquidity, we could experience ratings downgrades.
If commodity prices do not improve or worsen or if we are unable to increase our liquidity, we could experience ratings downgrades. For example, in January 2016, Moody’s downgraded our corporate family credit rating and the rating of our 8.875% senior unsecured notes due 2023 primarily due to the effect of high leverage, low natural gas prices and significant production curtailments on our ability to generate cash flow from operations. These ratings were subsequently upgraded by Moody’s in July 2017 and March 2019. In the event of any future downgrade, certain of our service providers, including our pipeline providers, could attempt to require us to post collateral or provide other assurances of our ability to perform our obligations under our contracts with such providers, which would negatively affect our liquidity and the borrowing base under our revolving credit facility and, in turn, increase the risk of additional downgrades.
Our development and exploration projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, or at all, which could lead to a decline in our oil and natural gas reserves.
The oil and natural gas industry is capital intensive. We have made, and if commodity prices rebound, expect to continue to make, substantial capital expenditures for the development and acquisition of oil and natural gas reserves. We expect to fund our capital expenditures in 2020 and subsequent to 2020 with cash on hand, cash generated by our operations and financing activities, which may include borrowings under our revolving credit facility, proceeds from non-core asset sales, and issuances of debt or equity. If we do not have sufficient borrowing availability under our revolving credit facility due to the current commodity price environment or otherwise, we may seek alternate debt or equity financing options (including, subject to compliance with our debt agreements, the issuance of first lien notes or other priority lien obligations), to sell assets or to further reduce our capital expenditures. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, natural gas, NGLs and oil prices and differentials, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction in realized natural gas, NGLs or oil prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production. Our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional indebtedness would require that a portion of our cash flows from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flows from operations to fund working capital, capital expenditures and acquisitions.
Our cash flows from operations and access to capital are subject to a number of variables, including, without limitation, the following:
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our proved reserves;
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the volumes and types of hydrocarbons we are able to produce from existing and future wells;
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our access to, and the cost of accessing, end markets for our production;
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the prices at which our production is sold;
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our ability to acquire, locate and develop new reserves;
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the levels of our operating expenses; and
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our ability to borrow under our revolving credit facility and issue additional debt and equity securities.
If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower natural gas, NGLs or oil prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If our cash on hand, cash flows
generated by our operations and available borrowings under our revolving credit facility are insufficient to meet our capital requirements, the failure to obtain additional financing could result in a further curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, financial condition and results of operations.
Changes in laws or government regulations regarding hydraulic fracturing could increase our costs of doing business, limit the areas in which we can operate and reduce our oil and natural gas production, which could adversely impact our business.
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and additives under pressure into target geological formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Presently, hydraulic fracturing is regulated primarily at the state level, typically by state oil and natural gas commissions and similar agencies. However, with increased public concern regarding the potential for hydraulic fracturing to adversely affect drinking water supplies or other environmental impacts, proposals have been made, and in many cases finalized, to enact federal, state and local legislation and regulations that would increase, or have increased, the regulatory burden imposed on hydraulic fracturing. For example, the U.S. Environmental Protection Agency (the “EPA”) issued regulations to control air emissions from oil and natural gas production and natural gas processing operations, then proposed and finalized additional air emissions regulations from oil and natural gas production and natural gas processing operations, completed a multi-year study examining the potential impacts of hydraulic fracturing on drinking water resources, established standards for wastewater discharges from oil and gas extraction activities and released an Advance Notice of Proposed Rulemaking to solicit public comment on potential chemical disclosure requirements. The U.S. Congress continues to consider amending the Safe Drinking Water Act to remove the exemption for hydraulic fracturing activities and to require disclosure of additives constituents of fluids used in the fracturing process. The Department of the Interior released final rules to regulate hydraulic fracturing activities on federal lands and to limit venting and flaring from production operations. Although the Department of the Interior hydraulic fracturing rules have been rescinded and the venting and flaring rule has been replaced with a less stringent version, both are the subject of litigation that could result in the prior version of such rules becoming effective and it is possible that amended or similar rules will be proposed and finalized. In addition, the United States has made commitments to reduce greenhouse gas emissions under the Paris Agreement, part of the United Nations Framework Convention on Climate Change. The Trump administration has begun the process to formally withdraw from the Paris Agreement, but under the terms of the agreement the U.S. will remain a party until November 4, 2020.
If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly for us to perform fracturing. Any such regulations limiting or prohibiting hydraulic fracturing or imposing punitive taxation could reduce our oil and natural gas exploration and production activities and, therefore, adversely affect our business. Such laws or regulations could also materially increase our costs of compliance and doing business by more strictly regulating how hydraulic fracturing wastes are handled or disposed.
Properties that we decide to drill may not yield natural gas, NGLs or oil in commercially viable quantities.
Properties that we decide to drill that do not yield natural gas, NGLs or oil in commercially viable quantities will adversely affect our results of operations and financial condition. Our project areas are in various stages of development, ranging from project areas with current drilling or production activity to project areas that consist of recently acquired leasehold acreage or that have limited drilling or production history. If the wells in the process of being drilled and completed do not produce sufficient revenues to return a profit or if we drill dry holes in the future, our business may be materially affected. In addition, there is no way to predict in advance of drilling and testing whether any particular prospect will yield natural gas, NGLs or oil in sufficient quantities to recover drilling and completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether natural gas, NGLs or oil will be present or, if present, whether natural gas, NGLs or oil will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:
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unexpected drilling conditions;
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title problems;
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pressure or lost circulation in formations;
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equipment failure or accidents;
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adverse weather conditions;
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compliance with environmental and other governmental or contractual requirements; and
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increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.
Hydrocarbon windows, phases or type curve areas have an inherent degree of variability and may change over time, and as a result, the available well data with respect to such windows, phases and type curve areas may not be indicative of the actual hydrocarbon composition for the windows, phases or type curve areas.
Based upon the well data available to us, we have grouped the publicly disclosed Utica Shale wells within the Utica Core Area into several distinct hydrocarbon windows, phases or type curve areas in an effort to better understand the thermal maturation variability within the Utica Core Area. However, there is an inherent degree of variability within such hydrocarbon windows, phases or type curve areas. Additionally, the well data we have utilized is predominantly based upon initial production rate, Btu content, natural gas yields and condensate yields, which may change over time. As a result, the well data with respect to the windows, phases and type curve areas within the Utica Core Area may not be indicative of the actual hydrocarbon composition for the windows, phases or type curve areas, or may not be the hydrocarbon composition of the windows, phases or type curve areas at the time we drill. Due to such factors, the performance, Btu content and NGLs and/or condensate yields of our wells may be substantially less than we anticipate or substantially less than performance and yields of other operators in the Utica Core Area, which may materially adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
We have been an early entrant into the Utica Core Area and have also been an early entrant into the portion of the Marcellus Shale underlying our Marcellus Area. As a result, our expected well results in these areas are uncertain, and the value of our undeveloped acreage will decline if well results are unsuccessful.
Our expected well results in the Utica Core Area and our Marcellus Area are more uncertain than well results in areas that are more developed and have a greater number of producing wells. As a result, our cost of drilling, completing and operating wells in the Utica Core Area and our Marcellus Area may be higher than initially expected, the ultimate production and reserves from these wells may be lower than initially expected and the value of our undeveloped acreage may decline. Additionally, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. We cannot assure you that unproved property acquired by us or
undeveloped acreage leased by us will be profitably developed, that wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.
Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.
Our operations involve utilizing some of the latest drilling and completion techniques as developed by us, other oil and gas exploration and production companies and our service providers. Risks that we face while drilling include, but are not limited to, the following:
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drilling wells that are significantly longer and/or deeper than more conventional wells;
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landing our wellbore in the desired drilling zone;
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staying in the desired drilling zone while drilling horizontally through the formation;
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running our casing the entire length of the wellbore; and
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being able to run tools and other equipment consistently through the horizontal wellbore.
Risks that we face while completing our wells include, but are not limited to, the following:
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the ability to fracture stimulate the planned number of stages;
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the ability to run tools the entire length of the wellbore during completion operations; and
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the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.
Drilling for and producing natural gas, NGLs and oil are high-risk activities with many uncertainties that could result in a total loss of investment or otherwise adversely affect our business, financial condition and results of operations.
Our future financial condition and results of operations will depend on the success of our development and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable production or that we will not recover all or any portion of our investment in such wells.
Our decisions to purchase, explore or develop prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “Items 1 and 2. Business and Properties-Oil and Natural Gas Data.” Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could materially reduce our borrowing capacity. In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences.
Further, many factors may curtail, delay or cancel our scheduled drilling projects, including, without limitation, the following:
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compliance with regulatory requirements, including limitations resulting from wastewater disposal, discharge of greenhouse gases, and limitations on hydraulic fracturing;
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pressure or irregularities in geological formations;
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shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;
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equipment failures, accidents or other unexpected operational events;
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lack of available gathering and processing facilities or delays in construction of gathering and processing facilities;
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lack of available capacity on interconnecting transmission pipelines;
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adverse weather conditions, such as blizzards and ice storms;
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issues related to compliance with environmental regulations;
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environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
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terrorist (including eco-terrorist) attacks targeting natural gas and oil related facilities and infrastructure;
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declines in natural gas, NGLs and oil prices;
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limited availability of financing at acceptable terms;
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title problems and well permit objections from coal operators; and
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limitations in the market for natural gas.
Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.
We have incurred losses from operations in a significant number of years since our inception and may do so in the future.
Although we generated net income of $31.8 million, $18.8 million, and $8.5 million for the years ended December 31, 2019, 2018, and 2017, respectively, we incurred a net loss in each of the prior years since our inception. Our development of and participation in prospects has required, and if commodity prices rebound will require, substantial capital expenditures. The uncertainty and factors described throughout this “Risk Factors” section may impede our ability to economically find, develop and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows from operating activities in the future, which could adversely affect the trading price of our common stock and our ability to fund our operations and fulfill our debt obligations.
We may not be able to generate sufficient cash to service all of our indebtedness, including our senior unsecured notes, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.
Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our revolving credit facility and our senior unsecured notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal of, or premium, if any, and interest on, our indebtedness when due.
If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, raise additional capital or restructure or refinance our indebtedness. Our ability to raise additional capital or restructure or refinance our indebtedness will depend on the condition of the credit, financial or other capital markets and our financial condition at such time. Any refinancing of our indebtedness could be at higher interest rates and may require us to comply with covenants that could further restrict our business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness.
In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. The value of our assets, particularly in times of low or volatile commodity prices, may not be sufficient to satisfy our
liquidity needs or to repay our indebtedness. Furthermore, the credit agreement governing our revolving credit facility, which we refer to as the Credit Agreement, and the indenture governing our senior unsecured notes restrict our subsidiaries’ ability to dispose of assets and our subsidiaries’ use of the proceeds from any such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations and fund our operations.
As of December 31, 2019, we had approximately $640.5 million in total indebtedness, excluding discount, and approximately $340.8 million of available borrowing capacity under our revolving credit facility (after giving effect to approximately $29.2 million of outstanding letters of credit and $130.0 million of outstanding borrowings).
In the future, we may not be able to access adequate funding under our revolving credit facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination, unwillingness of the lenders to increase their aggregate commitment up to an increased borrowing base amount or an unwillingness or inability on the part of one or more lenders to meet their funding obligations and the inability of other lenders to provide additional funding to cover each unwilling or defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future, and in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out our business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.
Our producing properties are primarily concentrated in the Appalachian Basin, which makes us vulnerable to risks associated with operating in one major geographic area.
Our producing properties are primarily geographically concentrated in the Appalachian Basin. At December 31, 2019, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, water shortages, weather related conditions or interruption of the processing or transportation of natural gas, NGLs or oil. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations. In addition, a number of areas within the Appalachian Basin have historically been subject to mining operations, the existence of which could require coordination to avoid adverse impacts as a result of drilling and mining in close proximity. These restrictions on our operations, and any similar restrictions, can cause delays or interruptions or can prevent us from executing our business strategy, which could have a material adverse effect on our financial condition and results of operations.
Due to the concentrated nature of our portfolio of natural gas and oil properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.
We own non-operating interests in properties developed and operated by third parties, and as a result, we are unable to control the operation and profitability of such properties.
We frequently participate as a non-operator in the drilling and completion of wells with third parties that exercise exclusive control over such operations. As a non-operator participant, we rely on the third-party operating company to successfully operate these properties pursuant to joint operating agreements and other similar contractual arrangements.
As a non-operator participant in these operations, we may not be able to maximize the value associated with these properties in the manner we believe appropriate, or at all. For example, we cannot control the success of drilling and development activities on properties operated by third parties, which depend on a number of factors under the control of a third party operator, including such operator’s determinations with respect to, among other things, the nature and timing of drilling and operational activities, the timing and amount of capital expenditures and the selection of suitable technology. In addition, the third-party operator’s operational expertise and financial resources and ability to gain the approval of other participants in drilling wells will impact the timing and potential
success of our drilling and development activities in a manner that we are unable to control. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are favorable to us could reduce our production and revenues, negatively impact our liquidity and cause us to spend capital in excess of our current plans, and have a material adverse effect on our financial condition and results of operations.
Our existing providers of gas gathering, processing and fractionation capacity may not be able to provide to us sufficient capacity for our production from the Utica Core Area, and as a result, we may be required to find alternative markets and gathering, processing or fractionation arrangements for our production from the Utica Core Area, which alternative arrangements may not be available on favorable terms, or at all.
A significant portion of our Utica Core Area acreage position is dedicated to long-term firm gas gathering, processing and fractionation agreements with primary terms of approximately 14 years. These agreements give us priority service and capacity over non-firm parties that wish to utilize the gas processing and fractionation plants and gas gathering system. As a result of such dedications, a significant portion of our operated wet gas acreage is committed to Blue Racer for gathering, processing and fractionation. Additionally, a significant portion of our operated dry gas acreage is committed to Eureka Midstream for gathering and a significant portion of our operated wet gas acreage is committed to EnLink Midstream for condensate gathering and stabilization. While we believe we have reserved sufficient capacity at these plants and on such systems to gather, process, fractionate and stabilize all of our projected production associated with our proved resources and a significant portion of our projected production from the Utica Core Area, that capacity may not be sufficient to handle all of our production or the plants and systems may experience significant mechanical problems or delays in construction or become unavailable to us due to unforeseen circumstances. As a result, we may be required to find alternative markets and gathering, processing or fractionation arrangements for our production from the Utica Core Area that is committed under these agreements, and such alternative arrangements may only be available on less favorable terms, or not at all.
We currently do not have long-term gathering agreements with providers with respect to a portion of our undeveloped acreage from our Marcellus Area, and we may not be able to enter into such agreements on favorable terms, or at all.
We have not entered into any gas gathering agreements with respect to our undeveloped acreage from a portion of our Marcellus Area. We may not be able to enter into any such agreements on favorable terms, or at all. Without such agreements, we may not receive priority service or capacity over third parties that utilize the same gas gathering systems. Our inability to obtain sufficient gas gathering for our production from a portion of our Marcellus Area could negatively impact our cash flows, financial condition and results of operations and reduce the overall value of our assets within this area.
Insufficient processing or takeaway capacity in the Appalachian Basin could cause significant fluctuations in our realized natural gas, NGLs and oil prices.
The Appalachian Basin natural gas business environment has historically been characterized by periods in which production has surpassed local processing and takeaway capacity, resulting in substantial discounts in the price received by producers such as us. A significant portion of our production from the Utica Core Area is currently being transported on pipelines that, after including the cost of such transportation, will consistently or periodically experience a negative differential to NYMEX Henry Hub prices.
Significant portions of our contracted firm transportation capacity have not been put into service. To the extent such projects are delayed or cancelled, and we are unable to secure additional long-term firm takeaway capacity on major pipelines that are in existence or currently under construction in our core operating area to accommodate our production and to manage basis differentials, it could have a material adverse effect on our financial condition and results of operations.
Oil and condensate produced in the Appalachian Basin has increased substantially. There is limited takeaway capacity for these products and our sales of these products are currently occurring, and we expect will continue to occur, at a discount to the benchmark WTI price. If our providers are unable to secure buyers for these products, it could have a material adverse effect on our financial condition and results of operations.
We currently are and, in the future, expect to be party to contracts with third parties that include contractual minimums.
We are currently party to and expect to continue to be party to service contracts with drilling rig companies that require us to make shortfall payments to such companies if our actual activity level falls below specified contractual minimum activity levels. Moreover, we have entered into service contracts, and in the future may enter into additional service contracts, such as firm pipeline transportation contracts with companies owning interstate pipelines, that require us or may require us to make shortfall payments if our actual throughput falls below specified contractual minimum volumes. For the year ended December 31, 2019, we incurred approximately $2.0 million in shortfall payments under such contracts. As such, we can provide no assurance that our activity levels will be sufficient to satisfy the minimum requirements under our drilling rig contracts or that our future volumes will be sufficient to satisfy the minimum requirements under any such firm transportation contracts. If we fail to satisfy the minimum activity levels or throughput requirements associated with such contracts, we would be obligated to make shortfall payments to our counterparties based on the difference between our actual activity levels and throughput volumes, respectively, and the contract minimums in each case. These differences and the associated shortfall payments could be significant, and we may not be able to generate sufficient cash to cover those obligations, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing.
Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.
The Credit Agreement contains a number of significant covenants, including restrictive covenants that restrict our and our subsidiaries’ ability to, among other things:
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incur additional indebtedness;
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sell assets;
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make loans to others;
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make investments;
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enter into mergers;
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hedge future production;
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incur liens;
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change the nature of our business; and
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engage in certain other transactions without the prior consent of the lenders.
The indenture governing our senior unsecured notes contains similar restrictive covenants. In addition, the Credit Agreement requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. These restrictions, together with those in the indenture governing our senior unsecured notes, may limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants of the Credit Agreement and the indenture governing our senior unsecured notes.
A breach of any covenant in the Credit Agreement or the indenture governing our senior unsecured notes would result in a default under the applicable agreement after any applicable grace periods. A default, if not waived or cured, could result in acceleration of the indebtedness outstanding under the relevant agreement and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or obtain sufficient capital to refinance such indebtedness. Even if a refinancing were available, it may not be on terms that are acceptable to us. Moreover, an increased interest rate is also payable in connection with a default under the Credit Agreement and certain payment defaults under the indenture governing our senior unsecured notes.
Any significant reduction in our borrowing base or reduction of lender commitments under our revolving credit facility, as a result of the periodic borrowing base redeterminations or otherwise, may negatively impact our ability to fund our capital expenditure plan.
We may fund a portion of our capital expenditure plan through 2020 with future borrowings under our revolving credit facility. The Credit Agreement limits the amounts we can borrow under our revolving credit facility from time to time up to a specified maximum borrowing base amount or the aggregate amount of lender commitments, whichever is less. The lenders, in their sole discretion, will determine a borrowing base on a semi-annual basis based upon the loan value assigned to the proved reserves attributable to our oil and gas properties evaluated in our most recent reserve report(s). Our lenders may further request two additional unscheduled borrowing base redeterminations during each calendar year. Any increase in the borrowing base will require the consent of the lenders holding 95.0% (or 100.0% if there are fewer than three lenders at the time of determination) of the outstanding credit amounts, or if none are then outstanding, 95% of the commitments (provided that no lender’s commitment may increase without its consent). Distinct from determinations of a borrowing base, each lender, in its sole discretion, will determine the maximum amount of loans it will commit to make under our revolving credit facility based, in part, on general economic considerations and its prevailing lending policies. Outstanding borrowings in excess of the lesser of the specified maximum borrowing base amount or the prevailing aggregate lender commitment must be repaid. If we fail to repay such excess borrowings on a timely basis, we must provide additional oil and gas properties as collateral to the extent necessary to eliminate the deficiency. As of December 31, 2019, the borrowing base under our revolving credit facility was $500 million with $130.0 million in outstanding borrowings under our revolving credit facility, resulting in borrowing availability of approximately $340.8 million (after giving effect to approximately $29.2 million of outstanding letters of credit).
We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.
We have made asset and business acquisitions in the past, including, most recently, the BRMR Merger, and we may continue to make acquisitions of assets or businesses in the future that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Further, the success of any completed acquisition, including the BRMR Merger, depends on our ability to integrate the acquired business effectively into our existing operations and such integration process may involve difficulties that require a disproportionate amount of our managerial and financial resources to resolve. We may also fail to realize the expected benefits of any completed acquisitions and completed acquisitions may subject us to significant transaction costs, unknown liabilities, and/or other unanticipated expenses, such as litigation expenses.
In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate successfully the acquired businesses and assets into our existing operations or to minimize any unforeseen liabilities or operational difficulties could have a material adverse effect on our financial condition and results of operations.
In addition, the Credit Agreement and the indenture governing our senior unsecured notes impose certain limitations on our ability to enter into mergers or combination transactions and to make investments. The Credit Agreement and the indenture governing our senior unsecured notes also limit our ability to incur certain indebtedness and liens, which could limit our ability to engage in acquisitions of businesses.
We may be subject to risks in connection with acquisitions of properties.
We have historically acquired assets and businesses that we feel complement our assets and business and may continue to do so in the future. The successful acquisition of producing properties requires an assessment of several factors, including:
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recoverable reserves;
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future natural gas, NGLs or oil prices and their applicable differentials;
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operating costs; and
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potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including, without limitation, assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.
In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. As a substantial portion of our reserve estimates are made without the benefit of a lengthy production history, any significant variance from the above assumption could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust reserve estimates to reflect production history, results of exploration and development, existing commodity prices and other factors, many of which are beyond our control.
You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated natural gas reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.
Reserve estimates for plays, such as the Utica Core Area, Flat Castle and our Marcellus Area, where we predominately operate, that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. Less production history may contribute to less accurate estimates of reserves, future production rates and the timing of development expenditures. Estimated reserves may not be correlated to perforated lateral length or completion technique. Furthermore, the lack of operational history for horizontal wells in the Utica Core Area, Flat Castle and our Marcellus Area may also contribute to the inaccuracy of future estimates of reserves and could result in our failing to achieve expected results in these plays. A material and adverse variance of actual production, revenues and expenditures from those underlying reserve estimates or management expectations would have a material adverse effect on our business, financial condition, results of operations and cash flows. Furthermore, given the amount of our total estimated proved reserves in relation to the amount of our outstanding debt obligations, the value of our assets may not be sufficient to satisfy our liquidity needs or to repay our indebtedness.
Our net identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the capital that we expect to be necessary to drill our identified drilling locations.
Our management team has specifically identified and scheduled certain well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas, NGLs and oil prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, topographical constraints, lease expirations, the ability to form units, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, governmental regulation, the ability to pool or unitize our acreage with acreage leased to other operators and approvals and other factors. Because of these uncertain factors, we do not know if the numerous drilling locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other identified drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. Further, some of the horizontal wells we intend to drill in the future may require unitization with adjacent leaseholds controlled by third parties. If these third parties are unwilling to unitize such leaseholds with ours, this may limit the total locations we can drill. As such, our actual drilling activities may materially differ from those presently identified.
As of December 31, 2019, after deducting wells that have been drilled or are in progress, we had identified approximately 220.0, 22.0, 133.0, 95.0 and 171.0 net undeveloped Dry Gas, Rich Gas, Condensate, Flat Castle and Marcellus locations, respectively. As a result of the limitations described above, including the recent significant declines in natural gas and oil prices, we may be unable to drill many of our identified drilling locations. In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations. For more information on our identified drilling locations, see “Items 1 and 2. Business and Properties-Our Properties.”
We have acreage that we must commence operations upon before lease expiration in order to hold the acreage by production. If we fail to drill sufficient wells to hold acreage, we incur substantial lease renewal costs, or if renewal is not feasible, lose our lease and prospective drilling opportunities.
Leases on our oil and natural gas properties typically have a primary term of 5 years, after which they expire unless, prior to expiration, we commence operations within the spacing units covering the undeveloped acres. As of December 31, 2019, we had leases representing approximately 29,149 gross (23,806 net) undeveloped acres scheduled to expire in 2020, 18,764 gross (12,449 net) undeveloped acres scheduled to expire in 2021, 11,001 gross (4,899 net) undeveloped acres scheduled to expire in 2022, 7,611 gross (4,233 net) undeveloped acres scheduled to expire in 2023, and 18,867 gross (13,650 net) undeveloped acres scheduled to expire in 2024 and beyond. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms, or at all. Moreover, many of our leases require lessor consent to create units larger than the leases currently permit, which may make it more difficult to hold our leases by production or optimally develop our leasehold position. Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, natural gas, NGLs and oil prices, the availability and cost of capital, drilling and production costs, the availability of drilling services and equipment, gathering systems and pipeline transportation constraints and regulatory approvals. In order to hold our current leases that are scheduled to expire in 2020 and 2021, we have deployed a strategy to convert our land extension payments into multi-year delay rental payments, which is designed to spread the costs beyond a single year. We cannot assure you that we will have the liquidity to execute on this strategy, that landowners will be willing to enter into this type of lease modification or that we will have the liquidity to otherwise deploy rigs when needed to hold this expiring acreage. Our reserves and future production, and therefore, our future cash flows and income, are highly dependent on successfully extending or developing our undeveloped leasehold acreage and the loss of any leases could materially adversely affect our ability to so develop such acreage.
The standardized measure of discounted future net cash flows from our proved reserves will not be the same as the current market value of our estimated oil and natural gas reserves.
You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements in effect at December 31, 2019, 2018, and 2017, we based the discounted future net cash flows from our proved reserves on the 12-month first-day-of-the-month oil and natural gas average prices without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:
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actual prices we receive for natural gas, NGLs and oil;
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actual cost of development and production expenditures;
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the effect of derivative transactions;
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the amount and timing of actual production; and
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changes in governmental regulations or taxation.
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating standardized measure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. As a corporation, we are treated as a taxable entity for federal income tax purposes, and our income taxes are dependent on our taxable income. Actual future prices and costs may differ materially from those used in the present value estimates included in this Annual Report, which could have a material effect on the value of our reserves.
We may incur losses as a result of title defects in the properties in which we invest.
Leases in the Appalachian Basin are particularly vulnerable to title deficiencies due to the long history of land ownership in the area, resulting in extensive and complex chains of title. In the course of acquiring the rights to develop oil and natural gas, it is standard procedure for us and the lessor to execute a lease agreement with payment subject to title verification. In most cases, we incur the expense of retaining lawyers, title abstractors or landmen to verify the rightful owners of the oil and gas interests prior to payment of such lease bonus to the lessor. There is no certainty, however, that a lessor has valid title to its lease’s oil and gas interests. In those cases, such leases are generally voided, and payment is not remitted to the lessor. As such, title failures may result in fewer net acres to us. Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Accordingly, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we could suffer a financial loss or an impairment of our assets.
The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.
At December 31, 2019, we had 2,729.8 Bcfe of total estimated proved reserves, of which approximately 45% were classified as proved undeveloped. Our approximately 1,235.6 Bcfe of estimated proved undeveloped reserves will require an estimated $920.6 million of development capital over the next 5 years. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.
Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.
Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we successfully conduct ongoing development and exploration activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future oil and natural gas reserves and production, and therefore our future cash flows and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.
Conservation measures and technological advances could reduce demand for natural gas, NGLs and oil.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to natural gas, NGLs and oil, technological advances in fuel economy and energy generation devices could reduce demand for natural gas, NGLs and oil. The impact of the changing demand for natural gas, NGLs and oil services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our derivative activities could result in financial losses or could reduce our earnings.
To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of natural gas and oil, we have entered into derivative instrument contracts for a significant portion of our natural gas, NGLs and oil production, including fixed-price swaps, basis swaps, collars and firm sales agreements. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.
Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:
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production is less than the volume covered by the derivative instruments;
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the counterparty to the derivative instrument defaults on its contractual obligations;
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there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or
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there are issues with regard to legal enforceability of such instruments.
The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and interest rates.
Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. Any default by a counterparty to these derivative contracts when they become due would have a material adverse effect on our financial condition and results of operations.
In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for natural gas, which could also have an adverse effect on our financial condition.
The inability of our significant customers to meet their obligations to us may adversely affect our financial results.
In addition to credit risk related to receivables from commodity derivative contracts, our principal exposures to credit risk are through joint interest receivables ($12.2 million at December 31, 2019) and the sale of our natural gas and oil production ($63.7 million in receivables at December 31, 2019). Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leased properties on which we wish to drill. We can do very little to choose who participates in our wells. For the year ended December 31, 2019, two customers, BP and Marathon, accounted for approximately 23% and 20% of our revenues, respectively. We do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
Our operating history is limited and as a result there is only limited historical financial and operating information available upon which to base an evaluation of our performance. Moreover, the historical financial and operating information included in this Annual Report may not be indicative of our future financial performance.
Our operating history is limited and as a result there is only limited historical financial and operating information available upon which to base an evaluation of our performance. Moreover, the historical financial and operating information included in this Annual Report may not be indicative of our future financial performance. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations- Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations” for a description of recent developments and transactions that may affect the comparability of our historical financial condition and results of operations for the periods presented to future periods. There can be no assurance that we will operate profitably. If our current business strategy is not successful, and we are not able to operate profitably, investors may lose some or all of their investment.
Our operations are subject to governmental laws and regulations, which may expose us to significant costs and liabilities that could exceed current expectations.
Our operations are subject to various federal, state and local governmental regulations. Matters subject to regulation include wastewater disposal, the spacing of wells, unitization and pooling of properties and taxation. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations, primarily relating to protection of human health and the environment. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, delays in granting permits and cancellation of leases. Moreover, these laws and regulations have continually imposed increasingly strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. We believe the trend of more expansive and stricter environmental legislation and regulations will continue for the foreseeable future. Please read “Items 1 and 2. Business and Properties-Regulation of the Oil and Natural Gas Industry” and “Items 1 and 2. Business and Properties-Regulation of Environmental and Occupational Safety and Health Matters” for a description of the laws and regulations that affect us.
We make assumptions and develop expectations about possible expenditures based on current laws and regulations and current interpretations of those laws and regulations. If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions may change, and new capital costs may be incurred to comply with such changes. In addition, new laws and regulations might adversely affect our operations and activities, including drilling, processing, storage and transportation, as well as waste management and air emissions.
Recent Ohio court decisions interpreting the Ohio Dormant Mineral Act and the Ohio Marketable Title Act relating to preservation of mineral rights by surface owners and heirs of reserved mineral interests could complicate title review, delay drilling activities and increase leasehold expenses with respect to some of our leasehold acreage in Ohio.
In September 2016, the Ohio Supreme Court issued a series of decisions relating to the Ohio Dormant Mineral Act, which we refer to as the ODMA. In the lead case, Corban v. Chesapeake Exploration L.L.C., the court concluded that the 1989 version of the ODMA did not transfer ownership of dormant mineral rights automatically, by operation of law. Instead, prior to 2006, surface owners were required to bring a quiet title action in order to establish abandonment of mineral rights. After June 30, 2006 (the effective date of the 2006 version of the ODMA), surface owners are required to follow the statutory notice and recording procedures enacted in 2006. As a result, going forward, it will be more difficult for a surface owner to achieve an abandonment of mineral rights as the Ohio Supreme Court held that the statutory notice and recording provisions of the 2006 version of the ODMA will apply. In addition, mineral interests that may previously have been believed to be automatically abandoned by operation of law under the ODMA will now be valid pursuant to the Ohio Supreme Court’s rulings.
Following the Ohio Supreme Court’s decision in Corban, many landowners began using the Ohio Marketable Title Act, which we refer to as the OMTA, as an alternative means to terminate severed oil and gas interests. The OMTA is self-executing and automatically extinguishes certain property interests created prior to a landowner’s chain of title to property. In January 2020, the Ohio Supreme Court accepted jurisdiction over West v. Bode, an appeal from the Seventh District Court of Appeals, to decide whether the ODMA supersedes and controls over the OMTA for disputes involving severed oil and gas interests, or whether the OMTA may be used as an alternative means to terminate severed mineral interests.
These recent Ohio court decisions, and the uncertainty of the continued availability of the OMTA to terminate severed mineral interests, may complicate title review, delay drilling activities and increase leasehold expenses with respect to our operations in Ohio where the majority of our acreage and producing properties are located, any of which could have an adverse effect on our results of operations and financial condition.
Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.
There is inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to the handling of our products as they are gathered, transported, processed and stored, air emissions related to our operations, historical industry operations, and water and waste disposal practices. Joint and several strict liability may be incurred without regard to fault under some environmental laws and regulations, including the Comprehensive Environmental Response, Compensation, and Liability Act, Resource Conservation and Recovery Act, the Oil Pollution Act, and analogous state laws, for the remediation of contaminated areas and in connection with spills or releases of natural gas, oil and wastes on, under, or from our properties and facilities. Private parties may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites at which we operate may be located near current or former third-party oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our compliance costs and the cost of any remediation that may become necessary. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.
We may be held responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.
Oil and natural gas producers’ operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water and water disposal options. Restrictions on the ability to obtain water or dispose of wastewater may impact our operations.
Water is an essential component of oil and natural gas production during the drilling, and in particular, hydraulic fracturing, process. Our inability to locate sufficient amounts of water or dispose of or recycle water used in our exploration and production operations could adversely impact our operations.
In addition, various studies have identified potential links between increases in seismic activity and the injection/disposal of water associated with oil and natural gas production, which could result in the imposition of operational limits or closure of disposal wells in areas where such links are suspected. For example, the Ohio Department of Natural Resources (“ODNR”) adopted rules that, among other things, allow the ODNR to require submission of a seismic monitoring plan, and require continuous monitoring of injection and annulus pressures on new wells.
We are subject to risks associated with climate change.
In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases (“GHGs”). The EPA has issued a series of GHG monitoring, reporting and emissions control rules for the oil and natural gas industry, and the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions. Almost one-half of the states have already taken measures to reduce emissions of GHGs primarily through the development of GHG emission inventories and/or regional GHG, cap-and-trade programs. While we are subject to certain federal GHG monitoring and reporting requirements, our operations currently are not adversely impacted by existing federal, state and local climate change initiatives, but this is potentially subject to change if new or more stringent requirements are imposed. In addition, the United States is currently a party to the Paris Agreement, an international agreement to reduce GHG emissions. Our business and our financial results could be adversely impacted to the extent that the United States implements any additional GHG regulations in accordance with such agreement. The Trump administration has begun the process to formally withdraw from the Paris Agreement, but under the terms of the agreement the U.S. will remain a party until November 4, 2020.
The costs that may be associated with the impacts of climate change and the regulation of GHGs have the potential to affect our business in many ways, including negatively impacting the costs we incur in providing our products and services, and the demand for and consumption of our products and services (due to changes in both costs and weather patterns). If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. At this time, however, it is not possible to estimate how future laws or regulations, or climatic changes may impact our business.
We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:
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environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline or river contamination;
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abnormally pressured formations;
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mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
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fires, explosions and ruptures of pipelines or processing facilities;
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personal injuries and death;
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natural disasters; and
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terrorist (including eco-terrorist) attacks targeting natural gas and oil related facilities and infrastructure.
Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:
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injury or loss of life;
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damage to and destruction of property, natural resources and equipment;
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pollution and other environmental damage;
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regulatory investigations and penalties;
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suspension of our operations; and
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repair and remediation costs.
In accordance with what we believe to be customary industry practice, we maintain insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any or all of the losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flows. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial condition. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.
Since hydraulic fracturing activities are a large part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and cleanup costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have no coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flows.
Market conditions or operational impediments may hinder our access to natural gas, NGLs or oil markets or delay our production.
Market conditions or the unavailability of satisfactory natural gas, NGLs or oil transportation arrangements may hinder our access to markets or delay our production. The availability of a ready market for our production depends on a number of factors, including the demand for and supply of natural gas, NGLs or oil and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms and concurrent with the completion of our wells could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of natural gas, NGLs or oil pipeline or gathering system capacity. In addition, if quality specifications for the third-party pipelines with which we connect change so as to restrict our ability to transport product, our access to markets could be impeded. If our production becomes shut in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market.
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.
The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. Some of the rigs performing work for us do so on a well-by-well basis and can refuse to provide such services at the conclusion of drilling on the current well. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. We cannot
predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.
Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market natural gas, NGLs and oil and secure trained personnel.
Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing natural gas, NGLs and oil and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive natural gas and oil properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.
The past success of our senior management with developing public and private natural gas and oil enterprises, and the expertise of our senior management in the acquisition, exploration and development of unconventional natural gas and oil properties does not guarantee our success or profitability.
As described in this Annual Report, most of our executive officers and other key personnel, including our President and Chief Executive Officer, John K. Reinhart, our Executive Vice President and Chief Operating Officer, Oleg E. Tolmachev, our Executive Vice President and Chief Financial Officer, Michael L. Hodges, and our Executive Vice President, Resource Planning and Development, Matthew H. Rucker, have substantial past experience in the acquisition, exploration and development of unconventional natural gas and oil properties, including experience at Ascent Resources, LLC, Chesapeake Energy Corporation, PayRock Energy II, LLC, Ward Energy Partners, LLC, and Rex Energy Corporation. However, the past experience and success of our executive officers and other key personnel with respect to previous endeavors in the natural gas and oil industry is not a guarantee of our future success or profitability.
The loss of senior management or technical personnel could adversely affect operations.
We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel, including our President and Chief Executive Officer, John K. Reinhart, our Executive Vice President and Chief Operating Officer, Oleg E. Tolmachev, our Executive Vice President and Chief Financial Officer, Michael L. Hodges, our Executive Vice President, Resource Planning and Development, Matthew H. Rucker, and our Executive Vice President, General Counsel and Corporate Secretary, Paul M. Johnston, could have a material adverse effect on our business, financial condition and results of operations.
Seasonal weather conditions and regulations intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in the areas where we operate.
Natural gas and oil operations in our operating areas can be adversely affected by seasonal weather conditions and regulations designed to protect certain species of wildlife. For example, we must comply with state and federal regulations aimed at protecting the Indiana and Northern Long-Eared bats, which have been listed as a protected species by both federal and state law, and those regulations restrict or increase the cost of our operations by, among other things, limiting our ability to clear trees to establish rights of way or pad locations on some of our acreage during certain periods of the year. See “Items 1 and 2. Business and Properties-Regulation of Environmental and Occupational Safety and Health Matters-Endangered Species Act and Migratory Bird Treaty Act.” Adverse seasonal weather conditions and wildlife regulations may limit our ability to operate in those areas and can intensify competition during those months for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. In addition, the designation of previously
unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration, development and production activities.
Acts of terrorism (including eco-terrorism) could have a material adverse effect on our financial condition, results of operations and cash flows.
Our assets and operations, and the assets and operations of our providers of gas gathering, processing, transportation and fractionation services, may be targets of terrorist activities (including eco-terrorist activities) that could disrupt our business or cause significant harm to our operations, such as full or partial disruption to our ability to produce, process, transport, market or distribute natural gas, NGLs and oil. Acts of terrorism, as well as events occurring in response to or in connection with acts of terrorism, could cause environmental and other repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, acts of terrorism, and the threat of such acts, could result in volatility in the prices for natural gas, NGLs and oil and could affect the markets for such commodities.
Cyber-attacks and threats could have a material adverse effect on our business, financial condition or results of operations.
Cyber-attacks may significantly affect the energy industry, including our operations and those of our suppliers and customers, as well as general economic conditions, consumer confidence and spending, and market liquidity. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. Our insurance may not protect us against such occurrences. We depend on digital technology in many areas of our business and operations, including, but not limited to, estimating quantities of oil and gas reserves, processing and recording financial and operating data, oversight and analysis of drilling operations, and communications with our employees and third-party customers or service providers. Deliberate attacks on our assets, or security breaches in our systems or infrastructure, or the systems or infrastructure of third-parties or the cloud, could lead to the corruption or loss of our proprietary and potentially sensitive data, delays in production or delivery of our production to customers, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, or other operational disruptions and third-party liabilities. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, ransomware, attempts to gain unauthorized access to data and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data.
As cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber-attacks. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our personnel, information, facilities and infrastructure may result in increased capital and operating costs. To date we have not experienced any material losses relating to cyber-attacks; however, there can be no assurance that we will not suffer such losses in the future. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations
Increases in interest rates could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flows used for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially adversely affect our ability to achieve our planned growth and operating results.
The enactment of derivatives legislation, and the promulgation of regulations pursuant thereto, could adversely affect our ability to use derivative instruments to hedge risks associated with our business.
Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was enacted on July 21, 2010 and establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to promulgate certain rules and regulations implementing the Dodd-Frank Act, with the CFTC responsible for the rules and regulations regarding derivatives of the type we may use to hedge certain risks. Although the CFTC has finalized most of its implementing regulations, others remain to be finalized and it is not possible at this time to predict when this will be accomplished. In addition, the CFTC and its staff regularly issue rule amendments and guidance, policy statements, and letters interpreting the derivatives provisions of the Dodd-Frank Act, the contents of which cannot be known in advance.
The Dodd-Frank Act enhanced the CFTC’s authority to establish rules and regulations setting position limits for certain futures and option contracts, including in the major energy markets, and, for the first time, swaps that are their economic equivalents. The CFTC’s initial position limits rules under the Dodd-Frank Act were vacated by the U.S. District Court for the District of Columbia in September 2012 before such rules took effect. However, the CFTC has proposed new rules that would place limits on positions in certain core futures, options and equivalent swaps contracts in certain physical commodities, subject to limited exceptions for certain bona fide hedging and other transactions. The CFTC has also adopted final rules regarding the aggregation of positions in determining compliance with federal position limits. While the position aggregation rules are final, the position limit rules themselves are not, and therefore the impact of those rules on our use of derivatives in commodities for which federal position limits would be imposed is uncertain at this time.
The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and execution on certain trading platforms. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing or trade execution. Although we expect to qualify for the end-user exception from the mandatory clearing and trade execution requirements for swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, margin rules for uncleared swaps could impact liquidity and therefore reduce our ability to execute hedges to reduce risk and protect cash flows. The margin rules are not in effect for all market participants, and therefore the impact of those provisions to us is uncertain.
The Dodd-Frank Act and regulations may have other effects, including requiring or causing the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which, among other impacts, could adversely affect our ability to plan for and fund capital expenditures.
Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and physically settled instruments related to oil and natural gas. Our revenues could therefore be adversely affected to the extent that the Dodd-Frank Act and regulations contribute to lower commodity prices.
Any of these consequences could have a material adverse effect on us, our financial condition or our results of operations.
Proposed changes to U.S. and state tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations and cash flows.
The elimination of tax deductions, as well as any other changes to or the imposition of new federal, state, local or non-US taxes (including the imposition of, or increases in production, severance or similar taxes) could also have a significant impact on our operations and financial performance. For example, the recently enacted U.S. federal income tax legislation commonly referred to as the “Tax Cuts and Jobs Act” is complex and far-reaching and made sweeping modifications to the Internal Revenue Code including lowering the corporate tax rate, changing credits and deductions, and moving to a semi-territorial system for corporations that have overseas earnings.
From time-to-time other U.S. and state tax legislative amendments may be proposed that, if enacted into law, would make additional significant changes to U.S. federal and state income tax laws, such as (i) the elimination of the immediate deduction for intangible drilling and development costs and (ii) an extension of the amortization period for certain geological and geophysical expenditures.
Additionally, we primarily operate in Ohio, Pennsylvania, and West Virginia. Legislation in these jurisdictions has been proposed from time to time that would impose or increase severance taxes on natural gas and oil extraction. For example, Ohio has previously considered, and, the Ohio Legislature continues to consider, proposals to increase the current severance tax imposed on production of natural gas or oil in Ohio. The Commonwealth of Pennsylvania requires an impact fee to be paid on all unconventional wells spud based on a price tier calculation for a period of 15 years. However, Pennsylvania’s governor and legislature have continued to discuss the imposition of a state severance tax on the extraction of natural resources, including natural gas produced from the Marcellus, Upper Devonian, and Utica Shale formations, either in replacement of or in addition to the existing impact fee. If any legislation imposing or increasing severance taxes is enacted, or other similar changes occur that tax our production or reduce or eliminate deductions currently available with respect to natural gas and oil exploration and development, it could adversely affect our business, financial condition, results of operations and cash flows.
Changes to state tax laws in response to recently enacted U.S. federal tax legislation or to impose new or increased taxes or fees on natural gas and oil extraction may result in an increase in the state taxes we pay.
Currently, many states conform their calculation of corporate taxable income to the calculation of corporate taxable income at the U.S. federal level. Due to recently enacted changes to U.S. federal income tax laws, certain states may change or modify the calculation of corporate taxable income at the state level. Any resulting increase in cost due to such changes could have an adverse effect on our financial position, results of operations and cash flows.
Future regulations relating to and interpretations of recently enacted U.S. federal income tax legislation may vary from our current interpretation of such legislation.
The Tax Cuts and Jobs Act is highly complex and subject to interpretation. The presentation of our financial condition and results of operations is based upon our current interpretation of the provisions contained in the Tax Cuts and Jobs Act. In the future, the Treasury Department and the Internal Revenue Service are expected to release regulations relating to and interpretive guidance of the legislation contained in the Tax Cuts and Jobs Act. Any significant variance of our current interpretation of such legislation from any future regulations or interpretive guidance could result in a change to the presentation of our financial condition and results of operations and could negatively affect our business.
Our ability to use our net operating loss carryforward to offset future taxable income is subject to certain limitations and therefore our future tax liability may be greater than expected.
As of December 31, 2019, we estimate that we have available to offset future U.S. federal taxable income approximately $1.4 billion of U.S. federal net operating loss carryforward, portions of which will begin to expire in 2034. Because of the Tax Cuts and Jobs Act, the anticipated federal net operating losses generated in 2018 and 2019 do not expire but may only offset 80% of our taxable income in any given year.
Additionally, our ability to utilize this net operating loss carryforward is dependent upon our ability to generate taxable income in future periods and is limited due to restrictions imposed on the utilization of net operating losses subsequent to an “ownership change” within the meaning of Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”).
Section 382 of the Code generally serves to limit a corporation’s use of its net operating losses after an “ownership change” in the stock of the corporation. Net operating losses on hand at the time of an ownership change are referred to as “pre-change losses.” These pre-change losses are subject to an annual limitation based upon the product of: (i) the fair market value of the loss corporation’s stock immediately before the ownership change multiplied by (ii) a federally published rate, which we refer to as the “long-term tax exempt rate”. Further, a loss corporation with a net unrealized built-in loss (“NUBIL”) at the time of the ownership change, meaning that the fair market value of its assets were less than their tax bases by more than 15%, must treat a disposition loss or similar depreciation/depletion within the 5 year post-ownership change period as a pre-change loss like a net operating loss for purposes of the Code Section 382 limitation.
BRMR underwent an ownership change under Section 382 of the Code when it emerged from bankruptcy on May 6, 2016, and incurred a second ownership change at the effective time of the BRMR Merger. Also, as a result of the BRMR Merger, we incurred an ownership change. As such, our pre-change losses as well as those of BRMR will be subject to the annual limitations provided in Section 382 of the Code.
Because U.S. federal net operating losses incurred before 2018 generally may be carried forward for up to 20 years, the annual limitation may effectively provide a cap on the cumulative amount of pre-ownership change losses, including certain recognized built-in losses that may be utilized. Any pre-ownership change losses in excess of the annual limitation may be lost. It is possible that the annual limitation imposed on our ability to use pre-ownership change losses could cause a net increase in our U.S. federal income tax liability and require U.S. federal income taxes to be paid earlier than otherwise would be paid if such annual limitations were not in effect.
Risks Related to Our Common Stock
The price of our common stock has historically been volatile, and this volatility may affect the price at which you could sell your common stock.
Our common stock began trading on the New York Stock Exchange (“NYSE”) on June 20, 2014 and since such date the market price of our common stock has ranged (after adjusting such market prices retroactively to reflect the 15-to-1 reverse stock split effected February 28, 2019) from a low of $2.59 per share in August 2019 to a high of $407.70 per share in June 2014. This volatility may prevent you from being able to sell your common stock at or above the price you paid for your common stock. The market price for our common stock could continue to fluctuate significantly for various reasons, including:
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general market conditions, including fluctuations in commodity prices;
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our operating and financial performance and drilling locations, including reserve estimates;
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quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;
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the public reaction to our press releases, our other public announcements and our filings with the SEC;
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strategic actions by our competitors;
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our failure to meet revenue, reserves or earnings estimates;
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changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;
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speculation in the press or investment community;
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the failure of research analysts to cover our common stock;
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sales of our common stock by us, certain investment funds (the “EnCap Funds”) managed by EnCap Investments L.P. (“EnCap”) or other stockholders, or the perception that such sales may occur;
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changes in accounting principles, policies, guidance, interpretations or standards;
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additions or departures of key management personnel;
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actions by our stockholders;
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domestic and international economic, legal and regulatory factors unrelated to our performance; and
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the realization of any risks described under this “Risk Factors” section.
The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition.
The EnCap Funds hold a significant amount of our common stock.
The EnCap Funds, which are managed by EnCap, hold a significant percentage of the outstanding shares of our common stock. So long as EnCap continues to control a significant amount of our common stock, it will continue to be able to strongly influence all matters requiring stockholder approval, regardless of whether or not other stockholders believe that a potential transaction is in their own best interests. In any of these matters, the interests of EnCap may differ or conflict with the interests of our other stockholders. The existence of a significant stockholder may also have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company. Moreover, this concentration of stock ownership may also adversely affect the trading price of our common stock to the extent investors perceive a disadvantage in owning stock of a company with a significant stockholder.
Conflicts of interest could arise in the future between us, on the one hand, and EnCap and its affiliates, including its portfolio companies, on the other hand, concerning, among other things, acquisitions and divestitures, potential competitive business activities or business opportunities.
EnCap is a leading provider of private equity to the independent sector of the U.S. oil and gas industry and manages investment funds that own a significant amount of our common stock. From time to time, we may acquire assets from entities affiliated with EnCap, including its portfolio companies, such as our acquisition of certain oil and gas leases, wells and other oil and gas rights and interests covering approximately 44,500 net acres located in the counties of Tioga and Potter in the Commonwealth of Pennsylvania from Travis Peak Resources, LLC (“Travis Peak”), which was completed on January 18, 2018 (such transaction, the “Flat Castle Acquisition”), divest assets to such entities or otherwise transact business with such entities. For example, EnCap has an interest in Caiman Energy II, LLC, which owns a significant interest in Blue Racer, a provider of firm gathering, processing and fractionation capacity for our operated acreage in the Rich Gas and Condensate Windows of the Utica Core Area. As a result, EnCap’s interests with respect to matters arising in connection with our arrangements with Blue Racer may not align with our interests. EnCap and its affiliates may also, from time to time, acquire interests in businesses that directly or indirectly compete with our business, or are significant existing or potential customers. EnCap and its affiliates may acquire or seek to acquire assets we seek to acquire, and as a result, those acquisition opportunities may not be available to us or may be more expensive for us to pursue. Any actual or perceived conflicts of interest with respect to the foregoing could make us susceptible to litigation, which could result in substantial costs or divert our management’s attention and resources or otherwise harm our business and adversely impact the trading price of our common stock.
The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the requirements of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”), may strain our resources, increase our costs and distract management.
We completed our initial public offering in June 2014. As a public company, we incur significant legal, accounting and other expenses that we did not incur as a private company. We also incur costs associated with our public company reporting requirements and with corporate governance requirements, including requirements under the Sarbanes-Oxley Act, as well as rules implemented by the SEC and the Financial Industry Regulatory Authority, Inc. These rules and regulations have increased our legal and financial compliance costs and make some activities more time-consuming and costly. These rules and regulations also make it more difficult and more expensive for us to obtain director and officer liability insurance. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our Board of Directors or as executive officers.
If we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our shares of common stock.
Future sales of our common stock could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute our stockholders’ ownership in us.
We may sell additional shares of common stock in subsequent public or private offerings. We may also issue additional shares of common stock or convertible securities. As of March 5, 2020, we had 35,826,888 outstanding shares of common stock. The EnCap Funds beneficially own an aggregate of 14,051,904 shares of our common stock, or approximately 39% of our total outstanding shares, a substantial portion of which has been registered with the SEC for resale. Upon the closing of the Flat Castle Acquisition, we entered into a registration rights agreement with Travis Peak, pursuant to which we agreed to register the resale of the shares of our common stock issued to Travis Peak, an entity affiliated with EnCap, in the Flat Castle Acquisition. Subject to compliance with the Securities Act or exemptions therefrom, certain of our employees may sell their shares of common stock into the public market.
Subject to the satisfaction of vesting conditions and Rule 144 restrictions applicable to our affiliates, shares registered under our registration statements on Form S-8 filed on July 2, 2014, June 2, 2017 and June 13, 2019 relating to our equity incentive plans are available for resale immediately in the public market without restriction.
We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.
Our second amended and restated certificate of incorporation and second amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
Our second amended and restated certificate of incorporation authorizes our Board of Directors to issue preferred stock without stockholder approval. If our Board of Directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our second amended and restated certificate of incorporation and second amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:
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limitations on the ability of our stockholders to call special meetings;
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providing that, subject to the rights of holders of any class or series of preferred stock, any action required or permitted to be taken by our stockholders must be taken at a duly held annual or special meeting of stockholders and may not be taken by any consent in writing of such stockholders;
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providing that our Board of Directors is expressly authorized to adopt, or to alter or repeal our second amended and restated bylaws; and
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establishing advance notice and information requirements for nominations for election to our Board of Directors or for proposing matters that can be acted upon by stockholders at stockholder meetings.
Our second amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers or other employees.
Our second amended and restated certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware (or, if the Court of Chancery does not have jurisdiction, another state court or a federal court located within the State of Delaware) shall, to the fullest extent permitted by applicable law and subject to applicable jurisdictional requirements, be the sole and exclusive forum for any current or former stockholder (including any current or former beneficial owner) to bring claims, including claims in the right of the Company, (i) that are based upon a violation of a duty by a current or former director, officer, employee or stockholder in such capacity, or (ii) as to which the General Corporation Law of the State of Delaware confers jurisdiction upon the Court of Chancery. Any person or entity purchasing or otherwise acquiring any interest in shares of our common stock shall be deemed to have notice of and consented to the provisions of our second amended and restated certificate of incorporation described above. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers or other employees, which may discourage such lawsuits against us and our directors, officers and other employees. Alternatively, if a court were to find these provisions of our second amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.
We do not intend to pay cash dividends on our common stock, and the Credit Agreement and the indenture governing our senior unsecured notes place certain restrictions on our ability to do so. Consequently, your only opportunity to achieve a return on your investment is if the price of our common stock appreciates.
We do not plan to declare cash dividends on shares of our common stock in the foreseeable future. Additionally, the Credit Agreement and the indenture governing our senior unsecured notes place certain restrictions on our ability to pay cash dividends. Consequently, your only opportunity to achieve a return on your investment in us will be if you sell your common stock at a price greater than you paid for it.
We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.
Our second amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our Board of Directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of our common stock.
We are a “smaller reporting company” and will be able to avail ourselves of reduced disclosure requirements applicable to smaller reporting companies, which could make our common stock less attractive to investors.
We are a “smaller reporting company,” as defined in the Exchange Act, and we intend to take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not “smaller reporting companies,” including reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements. We cannot predict if investors will find our common stock less attractive because we may rely on these exemptions. If some investors find our common stock less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.
If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock or if our operating results do not meet their expectations, our stock price could decline.
The trading market for our common stock is influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.
Item 1B.
Item 1B.
Unresolved Staff Comments
Not applicable.
Item 3.
Item 3.
Legal Proceedings
Information regarding the Company’s legal proceedings is set forth in “Note 14 -Commitments and Contingencies,” located in the notes to the Consolidated Financial Statements included in Part II Item 8 of this Annual Report and is incorporated herein by reference.
Item 4.
Item 4.
Mine Safety Disclosures
Not applicable.
PART II
Item 5.
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Common Stock
We have one class of common shares outstanding, having a par value of $0.01 per share (“Common Stock”). Our Common Stock is traded on the NYSE under the symbol “MR”. As of March 5, 2020, our Common Stock was held by 20 holders of record. The number of holders does not include the shareholders for whom shares are held in a “nominee” or “street” name.
Dividend Policy
We have not paid any cash dividends since our inception, and we do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the growth of our business. Our future dividend policy is within the discretion of our Board of Directors and will depend upon then-existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our Board of Directors may deem relevant. In addition, certain of our debt instruments place restrictions on our ability to pay cash dividends.
Item 6.
Item 6.
Selected Financial Data
Non-GAAP Financial Measure
“Adjusted EBITDAX” is a non-GAAP financial measure that we define as net income (loss) before interest expense or interest income; income taxes; write-down of abandoned leases; impairments; depreciation, depletion, amortization and accretion (“DD&A”); amortization of deferred financing costs; gain (loss) on derivative instruments, net cash receipts (payments) on settled derivative instruments, and premiums (paid) received on options that settled during the period; non-cash compensation expense; gain or loss from sale of interest in gas properties; exploration expenses; and other unusual or infrequent items. Adjusted EBITDAX, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with U.S. GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with U.S. GAAP. Adjusted EBITDAX provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations. However, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure:
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is widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors;
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helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and
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is used by our management team for various purposes, including as a measure of operating performance, in presentations to our Board of Directors, as a basis for strategic planning and forecasting and by our lenders pursuant to covenants under our revolving credit facility and the indenture governing our senior unsecured notes.
There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies. The following table represents a reconciliation of our net income (loss) from operations to Adjusted EBITDAX for the periods presented:
Item 7.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our Consolidated Financial Statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in natural gas, NGLs and oil prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Regarding Forward-Looking Statements.” Also, see the risk factors and other cautionary statements described in “Item 1A. Risk Factors” of this Annual Report. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
Overview of Our Business
We are an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin. On February 28, 2019, we completed a business combination (the “BRMR Merger”) with Blue Ridge Mountain Resources, Inc. (“BRMR”), and immediately thereafter, we changed our legal name from “Eclipse Resources Corporation” to “Montage Resources Corporation.” Except where the context indicates otherwise, the terms “we,” “us,” “our” or the “Company” as used herein refer, for periods prior to the completion of the BRMR Merger, to Eclipse Resources Corporation and its subsidiaries and, for periods following the completion of the BRMR Merger, to Montage Resources Corporation (“Montage”) and its subsidiaries.
As of December 31, 2019, we had assembled an acreage position approximating 233,800 net surface acres in Eastern Ohio, 38,700 net surface acres in Pennsylvania, and 49,700 net surface acres in West Virginia. Approximately 192,800 of our net acres are located in the Utica Shale fairway, which we refer to as the Utica Core Area, and approximately 55,300 net acres of stacked pay opportunity are also prospective for the highly liquids rich area of the Marcellus Shale in Eastern Ohio and West Virginia within what we refer to as our Marcellus Area. Additionally, we own approximately 74,100 net acres (which are approximately 80% held by production) outside of the Utica Core Area that may be prospective for the oil window of the Utica Shale.
We are the operator of approximately 98% of our net acreage within the Utica Core Area and our Marcellus Area. We intend to focus on developing our substantial inventory of horizontal drilling locations during commodity price environments that will allow us to generate attractive returns and will continue to opportunistically add to this acreage position where we can acquire acreage at attractive prices.
Outside of the Utica Core Area and our Marcellus Area, we had 1,002 gross (975.3 net) conventional wells operated under multiple subsidiaries as of December 31, 2019.
The net assets of our subsidiary, Magnum Hunter Production, Inc. (“MHP”), are classified as assets held for sale and liabilities associated with assets held for sale as of December 31, 2019. All operations of MHP are reflected as discontinued operations for all periods presented.
As of December 31, 2019:
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we were operating one horizontal rig;
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we had 370 gross (235.7 net) wells within the Utica Core Area and our Marcellus Area, of which 1 gross (0.7 net) were drilling, 6 gross (5.2 net) were awaiting completion, and 363 gross (229.8 net) had been turned to sales;
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we had average daily production for the year ended December 31, 2019 of approximately 547.8 MMcfe, which was comprised of approximately 77% natural gas, 14% NGLs and 9% oil; and
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our estimated proved reserves were 2,729.8 Bcfe, or 455.0 MMBoe, based on reserve reports prepared by SIS, our independent petroleum engineers for the year ended December 31, 2019, approximately 55% of which were proved developed reserves. Our estimated proved reserves were approximately 78% natural gas, 15% NGLs and 7% oil, as of December 31, 2019.
Factors That Significantly Affect Our Financial Condition and Results of Operations
We derive substantially all of our revenues from the production and sale of natural gas, NGLs and oil that are extracted from our natural gas during processing. During the year ended December 31, 2019, our revenues were derived approximately 57%, 13% and 23% from the production and sale of natural gas, NGLs and oil, respectively (with the remaining 7% of revenues primarily attributable to brokered natural gas and marketing revenue). Our revenues, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Natural gas, NGLs and oil prices have historically been volatile and may fluctuate widely in the future due to a variety of factors, including, but not limited to, prevailing economic conditions, supply and demand of hydrocarbons in the marketplace and geopolitical events such as wars or natural disasters. Sustained periods of low prices for these commodities would materially and adversely affect our financial condition, our results of operations, the quantities of natural gas, NGLs and oil that we can economically produce and our ability to access capital.
We use commodity derivative instruments to manage and reduce price volatility and other market risks associated with our production. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases. Our risk management activity is generally accomplished through over-the-counter commodity derivative contracts with large financial institutions. Additional information regarding our commodity derivative contracts is set forth in Note 7- Derivative Instruments to our Consolidated Financial Statements.
Like other businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well naturally decreases. Thus, an exploration and production company depletes part of its asset base with each unit of reserves it produces. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production in a cost-effective manner. Our ability to make capital expenditures to increase production from our existing reserves and to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to access capital in a cost-effective manner and to timely obtain drilling permits and regulatory approvals.
Our financial condition and results of operations, including the growth of production, cash flows and reserves, are driven by several factors, including:
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success in drilling new wells;
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natural gas, NGLs and oil prices;
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the availability of attractive acquisition opportunities and our ability to execute them;
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the amount of capital we invest in the leasing and development of our properties;
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facility or equipment availability and unexpected downtime;
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delays imposed by or resulting from compliance with regulatory requirements; and
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the rate at which production volumes on our wells naturally decline.
Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations
Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, for the following reasons:
Drilling Joint Venture. On December 22, 2017, we entered into definitive agreements with Sequel Energy Group LLC (“Sequel”) (an affiliate of GSO Capital Partners LP) to establish a drilling joint venture on our Utica Shale acreage in Guernsey and Monroe counties in southeast Ohio. We have committed funding from Sequel of up to $285 million to fund its proportionate share of two drilling programs comprising of 33 gross wells in aggregate. We retained 50% of our pre-carry working interest in the first program and 30% of our pre-carry working interest in the second program. We received a 15% carried interest on drilling and completion capital expenditures incurred in each well program, which was proportionately reduced based upon our retained pre-carry working interest in such well program, and a significant portion of Sequel’s working interest in each well program will revert to Montage once a certain return is realized by Sequel in each program. We are the operator of all wells drilled within each well program.
Flat Castle Acquisition. On January 18, 2018, Eclipse Resources-PA, LP, a wholly owned subsidiary of the Company, completed its acquisition of certain oil and gas leases, wells and other oil and gas rights and interests covering approximately 44,500 net acres located in the counties of Tioga and Potter in the Commonwealth of Pennsylvania from Travis Peak. The aggregate adjusted purchase price for the Flat Castle Acquisition was $92.2 million, which was paid entirely with approximately 2.5 million shares of the Company’s common stock.
BRMR Merger. On February 28, 2019, the Company completed its business combination transaction with Blue Ridge Mountain Resources, Inc. (“BRMR”) pursuant to that certain Agreement and Plan of Merger, dated as of August 25, 2018 and amended as of January 7, 2019 (the “Merger Agreement”), by and among the Company, Everest Merger Sub Inc., a Delaware corporation and a wholly owned subsidiary of the Company (“Merger Sub”), and BRMR. Pursuant to the Merger Agreement, Merger Sub merged with and into BRMR with BRMR continuing as the surviving corporation and a wholly owned subsidiary of the Company (the “BRMR Merger”).
As a result of the BRMR Merger, each share of common stock, par value $0.01 per share, of BRMR issued and outstanding immediately prior to the effective time of the BRMR Merger (the “Effective Time”), excluding certain Excluded Shares (as such term is defined in the Merger Agreement), was converted into the right to receive from the Company 0.29506 of a validly issued, fully-paid, and nonassessable share of common stock, par value $0.01 per share, of the Company. The exchange ratio reflects an adjustment to account for the 15-to-1 reverse stock split described below. Former stockholders of BRMR received cash for any fractional shares of the Company’s common stock to which they might have otherwise been entitled as a result of the BRMR Merger. In addition, upon completion of the BRMR Merger, all shares of BRMR restricted stock and all BRMR restricted stock units and performance interest awards were converted into the right to receive shares of common stock of the Company or cash, in each case as specified in the Merger Agreement.
Reverse Stock Split. Effective immediately prior to the Effective Time on February 28, 2019, the Company effected a 15-to-1 reverse stock split with respect to the issued and outstanding shares of its common stock. Holders of shares of the Company’s common stock immediately prior to the Effective Time received cash for any fractional shares of the Company’s common stock to which they might have otherwise been entitled as a result of the reverse stock split. The reverse stock split lowered the aggregate par value of the common stock reflected in the Consolidated Statements of Stockholders’ Equity to reflect the reduced shares with the offset to additional paid-in-capital. All issued and outstanding share and per share amounts as of and for the periods prior to February 28, 2019 presented in this Annual Report have been adjusted retroactively to reflect the reverse stock split in accordance with ASC 505 “Equity”.
Please see “Items 1 and 2. Business and Properties-Recent Developments” for a description of other recent developments and transactions that may affect the comparability of our historical financial condition and results of operations for the periods presented to future periods.
Source of Our Revenues
Substantially all of our historical revenues are derived from the production and sale of natural gas, NGLs and oil, and do not include the effects of derivatives. Revenues from product sales are a function of the volumes produced, prevailing market prices, product quality, gas Btu content and transportation costs. We generally sell production at a specific delivery point, pay transportation costs to a third party and receive proceeds from the purchaser with no transportation deduction. We record transportation costs as transportation, gathering and compression expense. We also may derive revenue from brokered gas or revenue we receive as a result of selling natural gas that is not related to our production and from the release of firm transportation capacity, which we refer to as brokered natural gas and marketing revenue. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.
Principal Components of Our Cost Structure
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Lease operating. These are day-to-day costs incurred to bring hydrocarbons out of the ground along with the daily costs incurred to maintain our producing properties. Such costs include compensation of our field employees, maintenance, repairs and workovers expenses related to our natural gas and oil properties.
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Transportation, gathering and compression. These are costs incurred to bring natural gas, NGLs, and oil to the market. Such costs include the costs to operate and maintain our low- and high-pressure gathering and compression systems as well as fees paid to third parties who operate gathering systems that transport our gas. They also include costs to process and extract NGLs from our produced gas and to transport our NGLs and oil to market. We often enter into fixed price long-term contracts that secure transportation and processing capacity which may include minimum volume commitments, the cost for which is included in these expenses to the extent that they are not excess capacity.
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Production and ad valorem taxes. Production taxes are paid on produced natural gas and oil based on a percentage of market prices or at fixed rates established by the applicable federal, state or local taxing authorities. Ad valorem taxes are generally based on reserve values at the end of each year.
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Brokered natural gas and marketing. These expenses are gas purchases for brokered natural gas that we buy and sell that is not related to our production and firm transportation capacity that is marketed to third parties.
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Depreciation, depletion, amortization and accretion. This includes the expensing of the capitalized costs incurred to acquire, explore and develop natural gas, NGLs and oil. As a successful efforts company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, and apportion these costs to each unit of production through depreciation, depletion and amortization expense. This also includes the monthly accretion of the future abandonment costs of tangible assets such as wells, service assets, pipelines and other facilities.
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Exploration. These are geological and geophysical costs, seismic costs, delay rentals and the costs of unsuccessful exploratory dry holes. This category also includes unproved property impairment and expenses associated with lease expirations.
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General and administrative. These costs include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other professional fees and legal compliance. Included in this category are any overhead expense reimbursements we receive from working interest owners of properties, for which we serve as the operator. These reimbursements are received during both the drilling and operational stages of a property’s life.
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Impairment of oil and gas properties. Properties are evaluated for impairment when circumstances indicate that the carrying value of an asset could exceed its fair value. When the carrying value exceeds the sum of the future undiscounted cash flows, an impairment loss is recognized for the difference between the fair market value and carrying value of the asset.
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Gain (loss) on derivative instruments. We utilize commodity derivative contracts to reduce our exposure to fluctuations in the price of gas. None of our derivative contracts are designated as hedges for accounting purposes. Consequently, our derivative contracts are marked-to-market each quarter with changes in fair value recognized currently as a gain or loss in our results of operations. The amount of future gain or loss recognized on derivative instruments is dependent upon future gas prices, which will affect the value of the contracts. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty. In addition to gains and losses recognized from changes in fair value of the derivative instruments, gain (loss) on derivative instruments includes actual amounts realized from settlement of derivative instruments upon expiration.
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Interest expense. We have historically financed a portion of our cash requirements with proceeds from fixed-rate senior unsecured notes and our revolving credit facility. As a result, we incur interest expense that is affected by our financing decisions.
How We Evaluate Our Operations
In evaluating our current and future financial results, we focus on production and revenue growth, lease operating expense, general and administrative expense (both before and after non-cash stock compensation expense) and operating margin per unit of production. In addition to these metrics, we use Adjusted EBITDAX, a non-GAAP measure, to evaluate our financial results. “Adjusted EBITDAX” is a non-GAAP financial measure that we define as net income (loss) before interest expense or interest income; income taxes; write-down of abandoned leases; impairments; depreciation, depletion, amortization and accretion (“DD&A”); amortization of deferred financing costs; gain (loss) on derivative instruments, net cash receipts (payments) on settled derivative instruments, and premiums (paid) received on options that settled during the period; non-cash compensation expense; gain or loss from sale of interest in gas properties; exploration expenses; and other unusual or infrequent items. Adjusted EBITDAX, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with U.S. GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with U.S. GAAP. Adjusted EBITDAX provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations.
In addition to the operating metrics above, as we grow our reserve base, we will assess our capital spending by calculating our operated proved developed reserves and our operated proved developed finding costs and development costs. We believe that operated proved developed finding and development costs are one of the key measurements of the performance of an oil and gas exploration and production company. We will focus on our operated properties as we control the location, spending and operations associated with drilling these properties. In determining our proved developed finding and development costs, only cash costs incurred in connection with exploration and development will be used in the calculation, while the costs of acquisitions will be excluded because our Board of Directors approves each material acquisition. In evaluating our proved developed reserve additions, any reserve revisions for changes in commodity prices between years will be excluded from the assessment, but any performance related reserve revisions are included.
We also continually evaluate our rates of return on invested capital in our wells. These rates of return calculations may include corporate level items such as land costs, general and administrative expenses, midstream costs and cash settled derivatives. We believe the quality of our assets combined with our technical and managerial expertise can generate attractive rates of return as we develop our acreage in the Utica Core Area and our Marcellus Area. We review changes in drilling and completion costs, lease operating costs, natural gas, NGLs and oil prices, well productivity, and other factors in order to focus our drilling on the highest rate of return areas within our acreage on a per well basis.
As a result of the closing of the BRMR Merger on February 28, 2019, BRMR’s assets and liabilities are included in the Consolidated Balance Sheet as of December 31, 2019 and BRMR’s revenues and expenses are included in the Consolidated Statements of Operations and Comprehensive Income (Loss) for the period from March 1, 2019 to December 31, 2019. (See Note 3- Acquisition).
Overview of the Year Ended December 31, 2019 Results
Operationally, our performance during the year ended December 31, 2019 reflects continued development of our acreage, while focusing on capital preservation in the current commodity price environment. During the year ended December 31, 2019, we achieved the following financial and operating results:
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increased our average daily net production for the year ended December 31, 2019 by 60% over the prior year, to 547.8 MMcfe per day;
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commenced drilling 32 gross (28.2 net) operated wells, commenced completions of 36 gross (30.0 net) operated wells and turned-to-sales 39 gross (30.8 net) operated wells during the year ended December 31, 2019;
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recognized net income of $31.8 million for the year ended December 31, 2019 compared to net income of $18.8 million for the year ended December 31, 2018; and
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realized Adjusted EBITDAX of $311.1 million for the year ended December 31, 2019 compared to $261.6 million for the year ended December 31, 2018. Adjusted EBITDAX is a non-GAAP financial measure. See “Item 6. Selected Financial Data-Non-GAAP Financial Measure” for more information.
Market Conditions
Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Prices for commodities, such as hydrocarbons, are inherently volatile. The following table lists average daily, high, low and average monthly settled NYMEX Henry Hub prices for natural gas and average daily, high and low NYMEX WTI prices for oil for the years ended December 31, 2019, 2018, and 2017:
Historically, commodity prices have been extremely volatile, and we expect this volatility to continue for the foreseeable future. A decline in commodity prices could materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. We make price assumptions that are used for planning purposes, and a significant portion of our cash outlays, including rent, salaries and noncancelable capital commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations on which these commitments were based, our financial results are likely to be adversely and disproportionately affected because these cash outlays are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices.
The Company is committed to profitably developing its natural gas, NGLs and oil reserves through an environmentally responsible and cost-effective operational plan. The Company’s revenues, earnings, liquidity and ability to grow are substantially dependent on the prices it receives for, and the Company’s ability to develop its reserves. Despite the continued low price commodity environment, the Company believes the long-term outlook for its business is favorable due to the Company's resource base, low cost structure, risk management strategies, and disciplined investment of capital.
It is difficult to quantify the impact of changes in future commodity prices on our reported estimated net proved reserves with any degree of certainty because of the various components and assumptions used in the process. However, the below sensitivity analysis demonstrates the potential impact of a 10% increase and decrease in commodity pricing to our reserves assuming all other inputs remain constant.
(1)
PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to standardized measure, please see “Items 1 and 2. Business and Properties-Oil and Natural Gas Data- Proved Reserves Additions and Revisions.”
We consider future commodity prices when determining our development plan, but many other factors are also considered. To the extent there is a significant increase or decrease in commodity prices in the future, we will assess the impact on our development plan at that time, and we may respond to such changes by altering our capital budget or our development plan. We plan to fund our development budget with a portion of the cash on hand at December 31, 2019, cash flows from operations, borrowings under our revolving credit facility, and proceeds from asset sales.
Results of Operations
The following discussion pertains to our results of operations, including analysis of our continuing operations regarding natural gas, NGLs and oil revenues, production, average product prices and average production costs and expenses for the years ended December 31, 2019, 2018, and 2017. The results of operations of MHP are reflected as discontinued operations for all periods presented.
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations
The following table illustrates the revenue attributable to our operations for the years ended December 31, 2019 and 2018:
Our production grew by approximately 74.7 Bcfe for the year ended December 31, 2019 over the year ended December 31, 2018, due to increased drilling activity and from wells acquired as part of the BRMR Merger. Our production for the years ended December 31, 2019 and 2018 is set forth in the following table:
Our average realized price (including cash settled derivatives and firm transportation) received during the year ended December 31, 2019 was $2.70 per Mcfe compared to $3.37 per Mcfe during the year ended December 31, 2018. Because we record transportation costs on two separate bases, as required by U.S. GAAP, we believe computed final realized prices of production volumes should include the total impact of firm transportation expense. Our average realized price (including all cash settled derivatives and firm transportation) calculation also includes all cash settlements for derivatives. Average realized price (excluding cash settled derivatives and firm transportation) does not include derivative settlements or firm transportation, which are reported in transportation, gathering and compression expense on the accompanying Consolidated Statements of Operations. Average realized price (including firm transportation and excluding cash settled derivatives) does include firm transportation where we receive net revenue proceeds from purchasers. Average realized price calculations for the years ended December 31, 2019 and 2018 are shown below:
Brokered natural gas and marketing revenue was $42.3 million in the year ended December 31, 2019 compared to $16.6 million in the year ended December 31, 2018. Brokered natural gas and marketing revenue includes revenue we receive as a result of selling natural gas that is not related to our production and from the release of firm transportation capacity. The increase from the year ended December 31, 2018 to the year ended December 31, 2019 was due to an increase in the amount of natural gas that was available for brokered gas transactions during the year ended December 31, 2019.
Costs and Expenses
We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per Mcfe, basis. The following table presents information about certain of our expenses for the years ended December 31, 2019 and 2018:
Lease operating expense was $43.4 million in the year ended December 31, 2019 compared to $28.3 million in the year ended December 31, 2018. Lease operating expense per Mcfe was $0.22 in the year ended December 31, 2019 compared to $0.23 in the year ended December 31, 2018. The increase of $15.1 million was primarily attributable to an increase in producing wells during the year ended December 31, 2019. The decrease of $0.01 per Mcfe was primarily due to a decrease in non-recurring workovers and fixed costs spread across increased production for the year ended December 31, 2019. Lease operating expenses include normally recurring expenses to operate our wells and non-recurring workovers and repairs.
Transportation, gathering and compression expense was $208.8 million in the year ended December 31, 2019 compared to $138.8 million in the year ended December 31, 2018. Transportation, gathering and compression expense per Mcfe was $1.04 in the year ended December 31, 2019 compared to $1.10 in the year ended December 31, 2018. The following table details our transportation, gathering and compression expenses for the years ended December 31, 2019 and 2018:
The increase of $70.1 million in the year ended December 31, 2019 was due to increased production and increased firm transportation capacity. The decrease of $0.06 per Mcfe was primarily due to a higher percentage of production attributable to natural gas and fixed firm transportation costs spread across increased production during the year ended December 31, 2019.
Production and ad valorem taxes are paid based on market prices and applicable tax rates. Production and ad valorem taxes were $12.1 million in the year ended December 31, 2019 compared to $10.1 million in the year ended December 31, 2018. Production and ad valorem taxes per Mcfe was $0.06 in the year ended December 31, 2019 compared to $0.08 in the year ended December 31, 2018. The increase of $2.0 million in aggregate production and ad valorem taxes was primarily due to increased production and well count. The decrease of $0.02 per Mcfe was primarily due to the recognition of a refund for production taxes from a state taxing authority during the year ended December 31, 2019.
Depreciation, depletion, amortization and accretion was approximately $156.0 million in the year ended December 31, 2019 compared to $134.9 million in the year ended December 31, 2018. This $21.2 million increase was primarily due to an increase in production and proved property costs during the year ended December 31, 2019. On a per Mcfe basis, DD&A decreased to $0.77 in the year ended December 31, 2019 from $1.07 in the year ended December 31, 2018, which was primarily due to a lower depletion rate resulting from our reserves increasing at a higher rate than our capital costs.
General and administrative expense was $70.9 million for the year ended December 31, 2019 compared to $44.4 million for the year ended December 31, 2018. General and administrative expense per Mcfe was $0.35 in each of the years ended December 31, 2019 and 2018. The increase of $26.5 million was primarily related to approximately $21.5 million of expenses related to the BRMR Merger incurred during the year ended December 31, 2019. Expenses were consistent on a per Mcfe basis due to the increase in expenses being offset by increased production for the year ended December 31, 2019 compared to December 31, 2018. General and administrative expense includes $8.8 million and $7.9 million of stock-based compensation expense for the years ended December 31, 2019 and 2018, respectively.
Other Operating Expenses
Our total operating expenses also include other expenses that generally do not trend with production. These expenses include brokered natural gas and marketing expense, exploration, rig termination and standby and (gain) loss on sale of assets. The following table details our other operating expenses for the years ended December 31, 2019 and 2018:
Brokered natural gas and marketing expense was $42.7 million for the year ended December 31, 2019 compared to $16.9 million in the year ended December 31, 2018. Brokered natural gas and marketing expense relate to gas purchases for brokered natural gas that we buy and sell that is not related to our production and firm transportation capacity that is marketed to third parties. The increase was primarily due to an increase in the amount of natural gas that was available for brokered gas transactions during the year ended December 31, 2019.
Exploration expense was $58.9 million in the year ended December 31, 2019 compared to $49.6 million in the year ended December 31, 2018. The following table details our exploration-related expenses for the years ended December 31, 2019 and 2018:
Delay rentals was $10.3 million in the year ended December 31, 2019 compared to $19.7 million in the year ended December 31, 2018. The decrease in delay rentals related to the reduction in future drilling activity and focusing renewals in our core acreage during the year ended December 31, 2019.
Impairment of unproved properties was $45.8 million in the year ended December 31, 2019 compared to $27.6 million in the year ended December 31, 2018. The increase in impairment charges during the year ended December 31, 2019 was the result of an increase in expected lease expirations due to a reduction in planned future drilling activity. As we continue to review our acreage positions and high grade our drilling inventory based on the current commodity price environment, additional leasehold impairments and abandonments may be recorded.
Rig termination and standby expense was $1.1 million in the year ended December 31, 2019 primarily related to the reduction in development activity. There was no rig termination and standby expense in the year ended December 31, 2018.
Gain on sale of assets was $0.5 million in the year ended December 31, 2019 and $1.8 million in the year ended December 31, 2018, each due to the sale of certain non-core assets.
Other Income (Expense)
Gain (loss) on derivative instruments was $48.6 million for the year ended December 31, 2019 compared to ($21.2) million for the year ended December 31, 2018, primarily due to changes in commodity prices during each year. Cash receipts (payments) were approximately $20.3 million and ($27.0) million for the derivative instruments that settled during the years ended December 31, 2019 and 2018, respectively.
Interest expense, net was $59.1 million for the year ended December 31, 2019 compared to $54.0 million for year ended December 31, 2018. The increase in interest expense was primarily due to our increased borrowings under our credit facility during the year ended December 31, 2019.
Income tax benefit (expense) was not recognized for the years ended December 31, 2019 and 2018 due to the Company recording a higher valuation allowance related to its pre-tax losses and reducing the valuation allowance to the extent of pre-tax income.
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017
Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations
The following table illustrates the revenue attributable to our operations for the years ended December 31, 2018 and 2017:
Our production grew by approximately 11.8 Bcfe for the year ended December 31, 2018 over the year ended December 31, 2017, as we placed new wells into production, partially offset by natural declines in well production. Our production for the years ended December 31, 2018 and 2017 is set forth in the following table:
Our average realized price (including cash settled derivatives and firm transportation) received during the year ended December 31, 2018 was $3.37 per Mcfe compared to $2.99 per Mcfe during the year ended December 31, 2017. Because we record transportation costs on two separate bases, as required by U.S. GAAP, we believe computed final realized prices of production volumes should include the total impact of firm transportation expense. Our average realized price (including all cash settled derivatives and firm transportation) calculation also includes all cash settlements for derivatives. Average realized price (excluding cash settled derivatives and firm transportation) does not include derivative settlements or firm transportation, which are reported in transportation, gathering and compression expense on the accompanying Consolidated Statements of Operations. Average realized price (including firm transportation and excluding cash settled derivatives) does include firm transportation where we receive net revenue proceeds from purchasers. Average realized price calculations for the years ended December 31, 2018 and 2017 are shown below:
Brokered natural gas and marketing revenue was $16.6 million in the year ended December 31, 2018 compared to $3.5 million in the year ended December 31, 2017. Brokered natural gas and marketing revenue includes revenue we receive as a result of selling natural gas that is not related to our production and from the release of firm transportation capacity. The increase from the year ended December 31, 2017 to the year ended December 31, 2018 was due to an increase in the amount of firm transportation that was available for brokered gas transactions or release to third parties during the year ended December 31, 2018.
Costs and Expenses
We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per Mcfe, basis. The following table presents information about certain of our expenses for the years ended December 31, 2018 and 2017:
Lease operating expense was $28.3 million in the year ended December 31, 2018 compared to $20.5 million in the year ended December 31, 2017. Lease operating expense per Mcfe was $0.23 in the year ended December 31, 2018 compared to $0.18 in the year ended December 31, 2017. The increase of $7.8 million and $0.05 per Mcfe was attributable to increases in producing wells and salt water disposal expenses during the year ended December 31, 2018. Lease operating expenses include normally recurring expenses to operate our wells and non-recurring workovers and repairs.
Transportation, gathering and compression expense was $138.8 million in the year ended December 31, 2018 compared to $124.8 million in the year ended December 31, 2017. Transportation, gathering and compression expense per Mcfe was $1.10 in each of the years ended December 31, 2018 and 2017. The following table details our transportation, gathering and compression expenses for the years ended December 31, 2018 and 2017:
The increase of $13.9 million in the year ended December 31, 2018 was due to our production growth and increased firm transportation expenses, which increased primarily due to additional capacity that came online during the second half of 2018. These expenses were consistent on a per unit basis as increased firm transportation and production costs were offset by lower contractual gathering rates.
Production and ad valorem taxes are paid based on market prices and applicable tax rates. Production and ad valorem taxes were $10.1 million in the year ended December 31, 2018 compared to $8.5 million in the year ended December 31, 2017. Production and ad valorem taxes per Mcfe was $0.08 in the year ended December 31, 2018 compared to $0.07 in the year ended December 31, 2017. The $1.6 million increase in aggregate production and ad valorem taxes was primarily due to increased production and well count. The increase of $0.01 on a per unit basis was driven by increased severance taxes associated with our increased liquids production.
Depreciation, depletion, amortization and accretion was approximately $134.9 million for the year ended December 31, 2018 compared to $119.4 million in the year ended December 31, 2017. This $15.6 million increase was primarily due to an increase in production and proved property costs. On a per Mcfe basis, DD&A decreased to $1.07 in the year ended December 31, 2018 from $1.05 in the year ended December 31, 2017, which was primarily due to a higher depletion rate resulting from our reserves increasing at a lower rate than our capital cost.
General and administrative expense was $44.4 million for the year ended December 31, 2018 compared to $44.6 million for the year ended December 31, 2017. General and administrative expense per Mcfe was $0.35 in the year ended December 31, 2018 compared to $0.39 in the year ended December 31, 2017. The $0.2 million decrease was primarily due to lower salaries and benefits associated with decreased head count, and lower professional fees partially offset by approximately $4.0 million of expense related to the BRMR Merger. The decrease of $0.04 per Mcfe was primarily due to fixed costs spread across increased levels of production as of December 31, 2018 compared to December 31, 2017. General and administrative expense includes $7.9 million and $9.3 million of stock-based compensation expense for the years ended December 31, 2018 and 2017, respectively.
Other Operating Expenses
Our total operating expenses also include other expenses that generally do not trend with production. These expenses include brokered natural gas and marketing expense, exploration, rig termination and standby and (gain) loss on sale of assets. The following table details our other operating expenses for the years ended December 31, 2018 and 2017:
Brokered natural gas and marketing expense was $16.9 million in the year ended December 31, 2018 compared to $3.2 million in the year ended December 31, 2017. Brokered natural gas and marketing expense relate to gas purchases for brokered natural gas that we buy and sell that is not related to our production and firm transportation capacity that is marketed to third parties. The increase was primarily due to an increase in the amount of firm transportation that was available for brokered gas transactions or release to third parties during the year ended December 31, 2018.
Exploration expense decreased to $49.6 million in the year ended December 31, 2018 compared to $50.2 million in the year ended December 31, 2017. The following table details our exploration-related expenses for the years ended December 31, 2018 and 2017:
Delay rentals were $19.7 million for the year ended December 31, 2018 compared to $17.7 million for the year ended December 31, 2017. The increase in delay rentals related to converting future lump-sum extension payments into annual delay rentals.
Impairment of unproved properties was $27.6 million for the year ended December 31, 2018 compared to $28.3 million for the year ended December 31, 2017. The decrease in impairment charges during the year ended December 31, 2018 was the result of a decrease in expected lease expirations due to the increase in our planned future drilling activity. As we continue to review our acreage positions and high grade our drilling inventory based on the current commodity price environment, additional leasehold impairments and abandonments may be recorded.
Rig termination and standby expense was less than $0.1 million for the year ended December 31, 2017. There was no rig termination and standby expense for the year ended December 31, 2018.
Gain on sale of assets was $1.8 million for the year ended December 31, 2018 and $0.2 million for the year ended December 31, 2017, each due to the sale of certain non-core assets.
Other Income (Expense)
Gain (loss) on derivative instruments was ($21.2) million for the year ended December 31, 2018 compared to $45.4 million for the year ended December 31, 2017, primarily due to changes in commodity prices during each year. Cash payments were approximately $27.0 million and $2.2 million for the derivative instruments that settled during the years ended December 31, 2018 and 2017, respectively.
Interest expense, net was $54.0 million for the year ended December 31, 2018 compared to $49.5 million for year ended December 31, 2017. The increase in interest expense was primarily due to our increased borrowings under our revolving credit facility during the year ended December 31, 2018.
Income tax benefit (expense) was not recognized for the years ended December 31, 2018 and 2017 due to the Company recording a higher valuation allowance related to its pre-tax losses and reducing the valuation allowance to the extent of pre-tax income.
Cash Flows, Capital Resources and Liquidity
Cash Flows
Cash flows from operations are primarily affected by production volumes and commodity prices. Our cash flows from operations also are impacted by changes in working capital. Short-term liquidity needs are satisfied by our operating cash flow, proceeds from asset sales, borrowings under our revolving credit facility, and proceeds from issuances of debt and equity securities. We sell a large portion of our production at the wellhead under floating market contracts.
Year Ended December 31, 2019 Compared to the Year Ended December 31, 2018
Net cash provided by operations in the year ended December 31, 2019 was $255.4 million compared to $225.1 million in the year ended December 31, 2018. The increase in cash provided from operating activities reflects working capital changes, operating income, timing of cash receipts and disbursements and the increase in our production during the year-over-year comparative periods.
Net cash used in investing activities in the year ended December 31, 2019 was $335.5 million compared to $266.3 million in the year ended December 31, 2018.
During the year ended December 31, 2019, we:
•
spent $349.7 million on capital expenditures for oil and natural gas properties;
•
received $2.0 million from assets sales; and
•
received $12.9 million as part of the assets acquired in the BRMR Merger.
During the year ended December 31, 2018, we:
•
spent $275.6 million on capital expenditures for oil and natural gas properties;
•
spent $1.0 million on property and equipment; and
•
received $10.4 million of proceeds relating to the sale of assets.
Net cash provided by financing activities in the year ended December 31, 2019 was $86.2 million compared to $29.9 million in the year ended December 31, 2018.
During the year ended December 31, 2019, we:
•
borrowed $97.5 million under our revolving credit facility;
•
withheld from employees’ shares totaling $6.7 million related to the settlement of equity compensation awards; and
•
paid $4.3 million of deferred financing costs related to the refinancing of our revolving credit facility and amendment to the Credit Agreement.
During the year ended December 31, 2018, we:
•
borrowed $32.5 million under our revolving credit facility; and
•
withheld from employees shares totaling $1.3 million related to the settlement of equity compensation awards.
Year Ended December 31, 2018 Compared to the Year Ended December 31, 2017
Net cash provided by operations in the year ended December 31, 2018 was $225.1 million compared to $112.7 million in the year ended December 31, 2017. The increase in cash provided from operating activities reflects working capital changes, operating income and the timing of cash receipts and disbursements during the year-over-year comparative periods.
Net cash used in investing activities in the year ended December 31, 2018 was $266.3 million compared to $292.5 million in the year ended December 31, 2017.
During the year ended December 31, 2018, we:
•
spent $275.6 million on capital expenditures for oil and natural gas properties;
•
spent $1.0 million on property and equipment; and
•
received $10.4 million of proceeds relating to the sale of assets.
During the year ended December 31, 2017, we:
•
spent $291.8 million on capital expenditures for oil and natural gas properties;
•
spent $2.0 million on property and equipment; and
•
received $1.3 million of proceeds relating to the sale of assets.
Net cash provided by (used in) financing activities in the year ended December 31, 2018 was $29.9 million compared to ($4.3) million in the year ended December 31, 2017.
During the year ended December 31, 2018, we:
•
borrowed $32.5 million under our revolving credit facility; and
•
withheld from employees shares totaling $1.3 million related to the settlement of equity compensation awards.
During the year ended December 31, 2017, we:
•
paid $1.8 million in financing costs associated with an amendment to the Credit Agreement that, among other things, increased the borrowing base under the revolving credit facility; and
•
withheld from employees’ shares totaling $2.0 million related to the settlement of equity compensation awards.
Liquidity and Capital Resources
Our main sources of liquidity and capital resources are internally generated cash flow from operations, asset sales, borrowings under our revolving credit facility and access to the debt and equity capital markets. We must find new and develop existing reserves to maintain and grow our production and cash flows. We accomplish this primarily through successful drilling programs, which requires substantial capital expenditures. We periodically review capital expenditures and adjust our budget based on liquidity, drilling results, leasehold acquisition opportunities, and commodity prices. We believe that our existing cash on hand, operating cash flow and available proceeds under our revolving credit facility will be adequate to meet our capital and operating requirements for 2020.
Future success in growing reserves and production will be highly dependent on capital resources available and the success of finding or acquiring additional reserves. We will continue using net cash on hand, cash flows from operations and proceeds available under our revolving credit facility to satisfy near-term financial obligations and liquidity needs, and as necessary, we will seek additional sources of debt or equity to fund these requirements. Longer-term cash flows are subject to a number of variables including the level of production and prices we receive for our production as well as various economic conditions that have historically affected the natural gas and oil business. Our ability to expand our reserve base is, in part, dependent on obtaining sufficient capital through internal cash flow, bank borrowings, asset sales, joint venture transactions or the issuance of debt or equity securities. There can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain capital expenditures that we believe are necessary to offset inherent declines in production and proven reserves.
As of December 31, 2019, we were in compliance with all of our debt covenants under the Credit Agreement and the indenture governing our 8.875% senior unsecured notes due 2023. Further, based on our current forecast and activity levels, we expect to remain in compliance with all such debt covenants for the next twelve months. However, if oil and natural gas prices decrease to lower levels, we are likely to generate lower operating cash flows, which would make it more difficult for us to remain in compliance with all of our debt covenants, including requirements with respect to working capital and interest coverage ratios. This could negatively impact our ability to maintain sufficient liquidity and access to capital resources.
Credit Arrangements
Long-term debt at December 31, 2019 and 2018, excluding discount, totaled $640.5 million and $543.0 million, respectively. Long-term debt includes both the senior unsecured notes outstanding and any outstanding borrowings against our revolving credit facility.
Information related to our credit arrangements is described in Note 9- Debt to our Consolidated Financial Statements and is incorporated herein by reference.
Commodity Hedging Activities
Our primary market risk exposure is in the prices we receive for our natural gas, NGLs and oil production. Realized pricing is primarily driven by the spot regional market prices applicable to our U.S. natural gas, NGLs and oil production. Pricing for natural gas, NGLs and oil production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.
To mitigate the potential negative impact on our cash flow caused by changes in natural gas, NGLs and oil prices, we may enter into financial commodity derivative contracts to ensure that we receive minimum prices for a portion of our future natural gas production when management believes that favorable future prices can be secured. We typically hedge the NYMEX Henry Hub price for natural gas, the WTI price for oil and a NGLs basket based on prices at Mont Belvieu, Texas.
Our hedging activities are intended to support natural gas, NGLs and oil prices at targeted levels and to manage our exposure to price fluctuations. The counterparty is required to make a payment to us for the difference between the floor price specified in the contract and the settlement price, which is based on market prices on the settlement date, if the settlement price is below the floor price. We are required to make a payment to the counterparty for the difference between the ceiling price and the settlement price if the ceiling price is below the settlement price. These contracts may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty, zero cost collars that set a floor and ceiling price for the hedged production, and puts which require us to pay a premium either up front or at settlement and allow us to receive a fixed price at our option if the put price is above the market price. Information regarding the derivative contracts we had entered into as of December 31, 2019 is set forth in Note 7- Derivative Instruments to our Consolidated Financial Statements.
By using derivative instruments to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. As of December 31, 2019, we had derivative instruments in place with Bank of Montreal, BP Energy Company, Capital One N.A., Citibank, Citizens Bank N.A., EDF Energy, J Aron, KeyBank N.A., Morgan Stanley, Royal Bank of Canada, and Wells Fargo. We believe all of such institutions currently are an acceptable credit risk. As of December 31, 2019, we did not have any past due receivables from counterparties.
Capital Requirements
Our primary needs for cash are for exploration, development and acquisition of natural gas and oil properties and repayment of principal and interest on outstanding debt. Our Board of Directors recently approved an initial capital budget for 2020 of between approximately $190 - $210 million, allocated approximately 95% for drilling and completions activities and approximately 5% for land capital requirements. The 2020 capital budget is expected to be substantially funded through internally generated cash flows, the Company’s current cash balance and borrowings under the revolving credit facility. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, natural gas, NGLs and oil prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and
competitive developments. A reduction in natural gas, NGLs or oil prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production and our proved reserves as well as our ability to maintain compliance with our debt covenants. Our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities, additional borrowings under our revolving credit facility or the sale of assets.
In addition, we may from time to time seek to pay down, retire or repurchase our outstanding debt using cash or through exchanges of other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on available funds, prevailing market conditions, our liquidity requirements, contractual restrictions in our Credit Agreement and other factors.
Capitalization
As of December 31, 2019 and 2018, our total debt, excluding debt discount and issuance costs, and capitalization were as follows (in millions):
Cash Contractual Obligations
Our contractual obligations include long-term debt, operating leases, drilling commitments, firm transportation, gas processing, gathering and compressions services, and asset retirement obligations. As of December 31, 2019 and 2018, we did not have significant capital leases, any significant off-balance sheet debt or other such unrecorded obligations, and we have not guaranteed any debt of any unrelated party. Our Consolidated Balance Sheet at December 31, 2019 reflects accrued interest payable of $21.3 million, compared to $21.7 million as of December 31, 2018. We paid the accrued interest balance in January 2020.
We have a contract for the service of one rig, which expires in October 2021, with the option to extend. We have also entered into firm transportation agreements with various pipelines in order to facilitate the delivery of production to market. These contracts commit us to transport minimum daily natural gas volumes at a negotiated rate or pay for any deficiencies at a specified reservation fee rate. We have also agreed to certain minimum commitments under long-term gas processing and gathering agreements as well as various gas compression agreements. For additional discussion, see “Items 1 and 2. Business and Properties-Midstream Agreements”.
Other
We lease acreage that is generally subject to lease expiration if operations are not commenced within a specified period, generally 5 years and approximately 56% of our leases in the Utica Core Area have a 3-5 year extension at our option. Based on our evaluation of prospective economics, including the cost of infrastructure to connect production, we have allowed acreage to expire and may allow additional acreage to expire in the future. To date, our expenditures to comply with environmental or safety regulations have not been a significant component of our cost structure and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.
Interest Rates
At December 31, 2019 and 2018, we had $510.5 million of senior unsecured notes outstanding, excluding discounts, which bore interest at a fixed cash interest rate of 8.875%, due semi-annually from the date of issuance.
Information related to our interest rates is described in Note 9- Debt to our Consolidated Financial Statements and is incorporated herein by reference.
Off-Balance Sheet Arrangements
We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance our liquidity or capital resource position, or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments which are described above under “-Cash Contractual Obligations”.
Inflation and Changes in Prices
Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in natural gas, NGLs and oil prices and the costs to produce our reserves. Natural gas, NGLs and oil prices are subject to significant fluctuations that are beyond our ability to control or predict. Although certain of our costs and expenses are affected by general inflation, it does not normally have a significant effect on our business. We expect costs in fiscal 2020 to continue to be a function of supply and demand. Further strengthening of commodity prices could stimulate demand for ancillary services causing services costs to increase. In the near term, the majority of our service costs are expected to remain flat in 2020 due to previously negotiated drilling, stimulation, and rentals contracts. Along with these contacts, we have secured quality service equipment and tenured personnel to limit our exposure to increasing service costs and improve operational efficiencies.
Critical Accounting Estimates
Our discussion and analysis of our financial condition and results of operations are based upon Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at year-end, the reported amounts of revenues and expenses during the year and proved natural gas and oil reserves. Some accounting policies involve judgments and uncertainties to such an extent there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Actual results could differ from the estimates and assumptions used.
Certain accounting estimates are considered to be critical if (a) the nature of the estimates and assumptions is material due to the level of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to changes; and (b) the impact of the estimates and assumptions on financial condition or operating performance is material.
Natural Gas and Oil Properties
We follow the successful efforts method of accounting for natural gas and oil producing activities. Unsuccessful exploration drilling costs are expensed and can have a significant effect on reported operating results. Successful exploration drilling costs and all development costs are capitalized and systematically charged to expense using the units of production method based on proved developed natural gas and oil reserves as estimated by our engineers and audited by independent engineers. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized on our Consolidated Balance Sheet if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well; and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Proven property leasehold costs are amortized to expense using the units of production method based on total proved reserves. Properties are assessed for impairment as circumstances warrant (at least annually) and impairments to value are charged to expense. The successful efforts method inherently relies upon the estimation of proved reserves, which includes proved developed and proved undeveloped volumes.
Proved reserves are defined by the SEC as those volumes of natural gas, NGLs, condensate and crude oil that geological and engineering data demonstrate with reasonable certainty are economically recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes
expected to be recovered 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. Although our engineers are knowledgeable of and follow the guidelines for reserves established by the SEC, including the rule revisions designed to modernize the oil and gas company reserves reporting requirements which were adopted effective December 31, 2009, the estimation of reserves requires engineers to make a significant number of assumptions based on professional judgment. Reserve estimates are updated at least annually and consider recent production levels and other technical information. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price and cost changes and other economic factors. Changes in natural gas, NGLs and oil prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions in turn cause adjustments in our depletion rates. We cannot predict what reserve revisions may be required in future periods. Reserve estimates are reviewed and approved by our Executive Vice President, Resource Planning and Development who reports directly to our President and Chief Executive Officer. To further ensure the reliability of our reserve estimates, we engage independent petroleum engineers to prepare our estimates of proved reserves at least annually. SIS, our independent petroleum engineers for the years ended December 31, 2019 and 2018, prepared 100% of our reserves in 2019 and 2018 and NSAI, our independent petroleum engineers, for all prior years, prepared 100% of our reserves in 2017, 2016, 2015, and 2014. For additional discussion, “See Items 1 and 2. Business and Properties-Oil and Natural Gas Data-Proved Reserves”.
Depletion rates are determined based on reserve quantity estimates and the capitalized costs of producing properties. As the estimated reserves are adjusted, the depletion expense for a property will change, assuming no change in production volumes or the capitalized costs. While total depletion expense for the life of a property is limited to the property’s total cost, proved reserve revisions result in a change in the timing of when depletion expense is recognized. Downward revisions of proved reserves may result in an acceleration of depletion expense, while upward revisions tend to lower the rate of depletion expense recognition. Estimated reserves are used as the basis for calculating the expected future cash flows from property asset groups, which are used to determine whether that property may be impaired. Reserves are also used to estimate the supplemental disclosure of the standardized measure of discounted future net cash flows relating to natural gas and oil producing activities and reserve quantities in Note 19- Supplemental Oil and Gas Information to our Consolidated Financial Statements. Changes in the estimated reserves are considered a change in estimate for accounting purposes and are reflected on a prospective basis.
We monitor our long-lived assets recorded in natural gas and oil properties in our Consolidated Balance Sheets to ensure they are fairly presented. We must evaluate our properties for potential impairment when circumstances indicate that the carrying value of an asset could exceed its fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future natural gas, NGLs and oil prices, an estimate of the ultimate amount of recoverable natural gas, NGLs and oil reserves that will be produced from the property asset groups future production, future production costs, future abandonment costs, and future inflation. The need to test a property asset group for impairment can be based on several factors, including a significant reduction in sales prices for natural gas, NGLs and/or oil, unfavorable adjustments to reserves, physical damage to production equipment and facilities, a change in costs, or other changes to contracts or environmental regulations. Our natural gas and oil properties are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. All of these factors must be considered when testing a property asset group carrying value for impairment.
The review is done by determining if the historical cost of proved and unproved properties less the applicable accumulated depreciation, depletion, amortization and accretion is less than the estimated undiscounted future net cash flows. The expected undiscounted future net cash flows are estimated based on our plans to produce and develop reserves. Expected undiscounted future net cash inflows from the sale of produced reserves are calculated based on estimated future prices and estimated operating and development costs. We estimate prices based upon market related information including published futures prices. The estimated future level of production, which is based on proved and risk adjusted probable reserves, has assumptions surrounding the future levels of prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. In certain circumstances, we also consider potential sales of properties to third parties in our estimates of undiscounted future cash flows. When the carrying value exceeds the sum of undiscounted future net cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future net cash flows using a discount rate similar to that used by market participants) and the carrying value of the asset. We cannot predict whether impairment charges may be required in the future.
We believe that a sensitivity analysis regarding the effect of changes in assumptions on estimated impairment is impractical to provide because of the number of assumptions and variables involved which have interdependent effects on the potential outcome. If natural gas, NGLs and oil prices decrease or drilling efforts are unsuccessful, we may be required to record additional impairments.
We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leaseholds. The costs are capitalized and evaluated (at least quarterly) as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. Potential impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors.
Acquisitions
As part of our business strategy, we periodically pursue the acquisition of oil and natural gas properties. The purchase price in an acquisition is allocated to the assets acquired and liabilities assumed based on their relative fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. Our most significant estimates in our allocation typically relate to the value assigned to future recoverable oil and natural gas reserves and unproved properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain.
Asset Retirement Obligations
We have significant obligations to remove tangible equipment and restore land at the end of natural gas and oil production operations. Removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future asset removal costs is difficult and requires us to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate retirement costs, inflation factors, credit-adjusted discount rates, timing of retirement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation (“ARO”), a corresponding adjustment is made to the natural gas and oil property balance. For example, as we analyze actual plugging and abandonment in formation, we may revise our estimate of current costs, the assumed annual inflation of the costs and/or the assumed productive lives of our wells. In addition, increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense, a component of depreciation, depletion, amortization and accretion in the accompanying Consolidated Statements of Operations. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates.
Revenue Recognition
Information related to revenue recognition is described in Note 2- Summary of Significant Accounting Policies to our Consolidated Financial Statements and is incorporated herein by reference.
Recent Accounting Pronouncements
Information related to recent accounting pronouncements is described in Note 2- Summary of Significant Accounting Policies to our Consolidated Financial Statements and is incorporated herein by reference.
Item 7A.
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Not applicable to smaller reporting companies.
Item 8.
Item 8.
Financial Statements and Supplementary Data
The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required for this Item are set forth beginning on page of this report and are incorporated herein by reference.
Item 9.
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Not applicable.
Item 9A.
Item 9A.
Controls and Procedures
Evaluation of Disclosure Controls and Procedures
The Company’s management carried out an evaluation (as required by Rule 13a-15(b) of the Exchange Act), with the participation of the Company’s President and Chief Executive Officer and Executive Vice President and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act), as of the end of the period covered by this Annual Report. Based upon this evaluation, the Company’s President and Chief Executive Officer and Executive Vice President and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this Annual Report, such that the information relating to the Company and its consolidated subsidiaries required to be disclosed by the Company in the reports that it files or submits under the Exchange Act (i) is recorded, processed, summarized, and reported, within the time periods specified in the SEC’s rules and forms, and (ii) is accumulated and communicated to the Company’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Controls
There has been no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15(d)-15(f) under the Exchange Act) during the fourth quarter of 2019 that has materially affected, or is reasonable likely to materially affect, the Company’s internal control over financial reporting.
Management’s Annual Report on Internal Control Over Financial Reporting
The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control system is designed to provide reasonable assurance to its management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Accordingly, even effective controls can provide only reasonable assurance with respect to financial statement preparation and presentation.
The Company’s management assessed the effectiveness of its internal control over financial reporting as of December 31, 2019. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013). Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2019.
Grant Thornton LLP, the independent registered public accounting firm that audited the Consolidated Financial Statements of the Company included in this annual report on Form 10-K, has issued its report on the effectiveness of the Company’s internal control over financial reporting at December 31, 2019. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31, 2019, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Montage Resources Corporation
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Montage Resources Corporation (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2019, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2019, and our report dated March 10, 2020 expressed an unqualified opinion on those financial statements.
Basis for opinion
The Company’s management is responsible 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 Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
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.
/s/ GRANT THORNTON LLP
Pittsburgh, Pennsylvania
March 10, 2020
Item 9B.
Item 9B.
Other Information
Not applicable.
PART III
Item 10.
Item 10.
Directors, Executive Officers and Corporate Governance
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2020 Annual Meeting of Stockholders.
Item 11.
Item 11.
Executive Compensation
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2020 Annual Meeting of Stockholders.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2020 Annual Meeting of Stockholders.
Item 13.
Item 13.
Certain Relationships and Related Transactions, and Director Independence
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2020 Annual Meeting of Stockholders.
Item 14.
Item 14.
Principal Accounting Fees and Services
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2020 Annual Meeting of Stockholders.
PART IV
Item 15.
Item 15.
Exhibits, Financial Statement Schedules
(1)
Financial Statements:
The Consolidated Financial Statements are listed on the Index to Financial Statements to this report beginning on page.
(2)
Financial Statement Schedules:
No financial statement schedules are submitted because of the absence of the conditions under which they are required, the required information is insignificant or because the required information is included in the Consolidated Financial Statements.
(3)
Exhibits:
The following exhibits are filed as part of this Annual Report.
EXHIBIT INDEX
Exhibit No.
Description
2.1#
Purchase and Sale Agreement, dated December 8, 2017, between Travis Peak Resources, LLC, Eclipse Resources-PA, LP, and Eclipse Resources Corporation (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the SEC on December 12, 2017).
2.2#
Option Agreement, dated as of December 8, 2017, by and among Cardinal Midstream II, LLC, Cardinal NE Holdings, LLC, Cardinal NE Midstream, LLC, Eclipse Resources Corporation, Eclipse Resources Midstream, LP, and Eclipse Resources-PA, LP (incorporated by reference to Exhibit 2.2 to the Company’s Current Report on Form 8-K filed with the SEC on December 12, 2017).
2.3#
Participation Agreement, dated December 22, 2017, by and among Eclipse Resources I, LP, Eclipse Resources-Ohio, LLC, and SEG-ECR LLC (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the SEC on December 28, 2017). +
2.4#
Agreement and Plan of Merger, dated as of August 25, 2018, among Eclipse Resources Corporation, Everest Merger Sub Inc., and Blue Ridge Mountain Resources, Inc. (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the SEC on August 27, 2018).
2.5
Amendment No. 1 to Agreement and Plan of Merger, dated as of January 7, 2019, among Eclipse Resources Corporation, Everest Merger Sub Inc., and Blue Ridge Mountain Resources, Inc. (incorporated by reference to Exhibit 2.2 to the Company’s Current Report on Form 8-K filed with the SEC on January 7, 2019).
3.1
Second Amended and Restated Certificate of Incorporation of Montage Resources Corporation (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on March 6, 2019).
3.2
Second Amended and Restated Bylaws of Montage Resources Corporation (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed with the SEC on March 6, 2019).
3.3
Certificate of Ownership and Merger, filed with the Secretary of State of the State of Delaware with an effective date of February 28, 2019 (incorporated by reference to Exhibit 3.3 to the Company’s Current Report on Form 8-K filed with the SEC on March 6, 2019).
4.1
Amended and Restated Registration Rights Agreement, dated January 28, 2015, by and among Eclipse Resources Corporation, Eclipse Resources Holdings, L.P., CKH Partners II, L.P., The Hulburt Family II Limited Partnership, Kirkwood Capital, L.P., EnCap Energy Capital Fund VIII, L.P., EnCap Energy Capital Fund VIII Co-Investors, L.P., EnCap Energy Capital Fund IX, L.P., Eclipse Management, L.P., Buckeye Investors L.P., GSO Capital Opportunities Fund II (Luxembourg) S.à.r.l., Fir Tree Value Master Fund, L.P., Luxor Capital Partners, LP and Luxor Capital Partners Offshore Master Fund, LP (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on January 29, 2015).
4.2
Specimen Common Stock Certificate of Montage Resources Corporation (incorporated by reference to Exhibit 4.2 to the Company’s Annual Report on Form 10-K filed with the SEC on March 15, 2019).
4.3
Indenture, dated as of July 6, 2015, between Eclipse Resources Corporation, the guarantors party thereto and Deutsche Bank Trust Company Americas, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed with the SEC on July 8, 2015).
4.4
Registration Rights Agreement, dated as of January 18, 2018, by and among Eclipse Resources Corporation, Eclipse Resources-PA, LP, and Travis Peak Resources, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on January 22, 2018).
4.5*
Description of Securities Registered Under Section 12 of the Securities Exchange Act of 1934, as amended.
Exhibit No.
Description
10.1
Second Amended and Restated Credit Agreement, dated as of June 11, 2015, by and among Eclipse Resources Corporation, as borrower, Bank of Montreal, as administrative agent, and each of the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 12, 2015).
10.2
First Amendment to Second Amended and Restated Credit Agreement, dated January 21, 2016, by and among Eclipse Resources Corporation, as borrower, Bank of Montreal, as administrative agent, and each of the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on January 25, 2016).
10.3
Second Amendment to Second Amended and Restated Credit Agreement, dated as of February 24, 2016, by and among Eclipse Resources Corporation, as borrower, Bank of Montreal, as administrative agent, and each of the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on February 26, 2016).
10.4
Third Amendment to Second Amended and Restated Credit Agreement, dated as of February 24, 2017, by and among Eclipse Resources Corporation, as borrower, Bank of Montreal, as administrative agent, and each of the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on March 2, 2017).
10.5
Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of August 1, 2017, by and among Eclipse Resources Corporation, as borrower, Bank of Montreal, as administrative agent, and each of the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on August 7, 2017).
10.6
Third Amended and Restated Credit Agreement, dated as of February 28, 2019, among Montage Resources Corporation, Bank of Montreal, as administrative agent, the lenders party thereto, and BMO Capital Markets Corp., Capital One, National Association, and KeyBank National Association, as joint lead arrangers and joint bookrunners (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on March 6, 2019).
10.7
First Amendment to Third Amended and Restated Credit Agreement, dated as of September 19, 2019, by and among Montage Resources Corporation, as borrower, Bank of Montreal, as administrative agent, and each of the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on November 8, 2019).
10.8
Second Amendment to Third Amended and Restated Credit Agreement, dated as of November 11, 2019, by and among Montage Resources Corporation, as borrower, Bank of Montreal, as administrative agent, and each of the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on November 15, 2019).
10.9†
Eclipse Resources Corporation 2014 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 24, 2014).
10.10†
Eclipse Resources Corporation 2014 Long-Term Incentive Plan, as amended by the First Amendment (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on May 18, 2017).
10.11†
Montage Resources Corporation 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 20, 2019).
10.12
Master Reorganization Agreement, dated June 6, 2014, by and among Eclipse Resources I, LP, Eclipse GP, LLC, EnCap Energy Capital Fund VIII, L.P., EnCap Energy Capital Fund VIII Co-Investors, L.P., EnCap Energy Capital Fund IX, L.P., CKH Partners II, L.P., The Hulburt Family II Limited Partnership, Kirkwood Capital, L.P., Eclipse Management, L.P., Eclipse Resources Holdings, L.P., Eclipse Resources Corporation and Benjamin W. Hulburt, Christopher K. Hulburt and Thomas S. Liberatore (incorporated by reference to Exhibit 10.9 to Amendment No. 2 to the Company’s Registration Statement on Form S-1 filed with the SEC on June 9, 2014).
10.13†
Form of Indemnification Agreement for Eclipse Resources Corporation Officers and Directors (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to the Company’s Registration Statement on Form S-1 filed with the SEC on June 2, 2014).
Exhibit No.
Description
10.14†
Amended and Restated Executive Employment Agreement, dated as of August 17, 2017, by and between Eclipse Resources Corporation and Benjamin W. Hulburt (incorporated by referenced to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on August 18, 2017).
10.15†
Amended and Restated Executive Employment Agreement, dated as of August 17, 2017, by and between Eclipse Resources Corporation and Matthew R. DeNezza (incorporated by referenced to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on August 18, 2017).
10.16†
Amended and Restated Executive Employment Agreement, dated as of August 17, 2017, by and between Eclipse Resources Corporation and Christopher K. Hulburt (incorporated by referenced to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the SEC on August 18, 2017).
10.17†
Amended and Restated Executive Employment Agreement, dated as of January 1, 2017, by and between Eclipse Resources Corporation and Oleg Tolmachev (incorporated by referenced to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on January 3, 2017).
10.18†
Retention Agreement, dated as of February 28, 2019, by and between Montage Resources Corporation and Oleg Tolmachev (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on May 9, 2019).
10.19†
Executive Employment Agreement, effective as of March 1, 2019, by and between Montage Resources Corporation and John K. Reinhart (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on April 16, 2019).
10.20†
Executive Employment Agreement, effective as of March 1, 2019, by and between Montage Resources Corporation and Michael L. Hodges (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on April 16, 2019).
10.21†
Executive Employment Agreement, effective as of June 25, 2019, by and between Montage Resources Corporation and Timothy J. Loos (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 28, 2019).
10.22†
Executive Employment Agreement, effective as of March 1, 2019, by and between Montage Resources Corporation and Oleg E. Tolmachev (incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on August 8, 2019).
10.23†
Executive Employment Agreement, effective as of March 1, 2019, by and between Montage Resources Corporation and Matthew H. Rucker (incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on August 8, 2019).
10.24†
Executive Employment Agreement, effective as of March 1, 2019, by and between Montage Resources Corporation and Paul M. Johnston (incorporated by reference to Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on August 8, 2019).
10.25†
Montage Resources Corporation Non-Employee Director Compensation Policy (incorporated by reference to Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on August 8, 2019).
10.26†
Restricted Stock Award Agreement, effective as of February 28, 2019, by and between Montage Resources Corporation and Oleg E. Tolmachev (incorporated by reference to Exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on August 8, 2019).
10.27
Securities Purchase Agreement, dated as of December 27, 2014, by and between Eclipse Resources Corporation, CKH Partners II, L.P., The Hulburt Family II Limited Partnership, Kirkwood Capital, L.P., EnCap Energy Capital Fund VIII, L.P., EnCap Energy Capital Fund VIII Co-Investors, L.P., EnCap Energy Capital Fund IX, L.P., Buckeye Investors L.P., GSO Capital Opportunities Fund II L.P., GSO Eclipse Holdings I LP, Fir Tree Value Master Fund, L.P., Luxor Capital Partners, LP and Luxor Capital Partners Offshore Master Fund, LP. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on December 29, 2014).
10.28†
Form of Restricted Stock Unit Award Agreement for Employees (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on March 2, 2016).
Exhibit No.
Description
10.29†
Form of Performance Unit Award Agreement for Employees (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on March 2, 2016).
10.30†
Form of Restricted Stock Unit Award Agreement for 2015 Bonuses (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the SEC on March 2, 2016).
10.31†
Form of Performance Unit Award Agreement for Employees (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on April 26, 2016).
10.32†
Form of Restricted Stock Unit Award Agreement for Officers and Employees (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on June 20, 2019).
10.33†
Form of Performance Unit Award Agreement for Officers and Employees (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the SEC on June 20, 2019).
10.34†
Form of Restricted Stock Award Agreement for Non-Employee Directors (incorporated by reference to Exhibit 10.10 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on August 8, 2019).
10.35
Voting Agreement, dated as of August 25, 2018, among Eclipse Resources Corporation, Blue Ridge Mountain Resources, Inc., and the stockholders of Blue Ridge Mountain Resources, Inc. party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on August 27, 2018).
10.36
Voting Agreement, dated as of August 25, 2018, among Eclipse Resources Corporation, Blue Ridge Mountain Resources, Inc., and the stockholders of Eclipse Resources Corporation party thereto (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on August 27, 2018).
10.37
Lock-Up Agreement, dated as of August 25, 2018, from the stockholders of Eclipse Resources Corporation party thereto (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the SEC on August 27, 2018).
10.38
Form of Lock-Up Agreement from the stockholders of Blue Ridge Mountain Resources, Inc. party thereto (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the SEC on August 27, 2018).
10.39
Board Observation Agreement, dated as of August 25, 2018, by and among Eclipse Resources Corporation, EnCap Energy Capital Fund VIII, L.P., EnCap Energy Capital Fund VIII Co-Investors, L.P., and EnCap Energy Capital Fund IX, L.P. (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed with the SEC on August 27, 2018).
10.40†
Separation and Release Agreement, dated as of August 24, 2018, by and between Eclipse Resources Corporation and Benjamin W. Hulburt (incorporated by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed with the SEC on August 27, 2018).
10.41†
Separation and Release Agreement, dated as of August 24, 2018, by and between Eclipse Resources Corporation and Matthew R. DeNezza (incorporated by reference to Exhibit 10.7 to the Company’s Current Report on Form 8-K filed with the SEC on August 27, 2018).
10.42†
Separation and Release Agreement, dated as of August 24, 2018, by and between Eclipse Resources Corporation and Christopher K. Hulburt (incorporated by reference to Exhibit 10.8 to the Company’s Current Report on Form 8-K filed with the SEC on August 27, 2018).
10.43†
Amendment to Separation and Release Agreement, dated as of November 30, 2018, by and between Eclipse Resources Corporation and Matthew R. DeNezza (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on December 4, 2018).
21.1*
List of Subsidiaries of Montage Resources Corporation
23.1*
Consent of Grant Thornton LLP
Exhibit No.
Description
23.2*
Consent of Software Integrated Solutions Division of Schlumberger Technology Corporation
31.1*
Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241)
31.2*
Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241)
32.1**
Certification of the Company’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350)
32.2**
Certification of the Company’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350)
99.1*
Software Integrated Solutions Division of Schlumberger Technology Corporation, Summary of Reserves for Unconventional Properties as of December 31, 2019 (Montage Resources Corporation).
99.2
Software Integrated Solutions Division of Schlumberger Technology Corporation, Summary of Reserves for Unconventional Properties as of December 31, 2018 (Eclipse Resources Corporation) (incorporated by reference to Exhibit 99.1 to the Company’s Annual Report on Form 10-K filed with the SEC on March 15, 2019).
99.3
Netherland Sewell & Associates, Inc., Summary of Reserves for Unconventional Properties as of December 31, 2017 (Eclipse Resources Corporation) (incorporated by reference to Exhibit 99.1 to Amendment No. 1 on Form 10-K/A to the Company’s Annual Report on Form 10-K filed with the SEC on December 7, 2018).
101.INS*
Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL Document
101.SCH*
Inline XBRL Taxonomy Extension Schema Document
101.CAL*
Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*
Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*
Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*
Inline XBRL Taxonomy Extension Presentation Linkbase Document
104*
Cover Page Interactive Data File (embedded within the Inline XBRL document)
#
Pursuant to Item 601(b)(2) of Regulation S-K, certain schedules and similar attachments to this agreement have been omitted. The registrant hereby agrees to furnish supplementally a copy of any omitted schedule or similar attachment to the Securities and Exchange Commission upon request.
*
Filed herewith.
**
These exhibits are furnished herewith and shall not be deemed “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act.
+
Confidential treatment has been granted for certain portions of this Exhibit pursuant to Rule 24b-2 of the Exchange Act, which portions have been omitted and filed separately with the Securities and Exchange Commission.
†
Management contract or compensatory plan or arrangement.
Item 16.
Form 10-K Summary
None.
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.
March 10, 2020
MONTAGE RESOURCES CORPORATION
(Registrant)
/s/ John K. Reinhart
John K. Reinhart
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant in the capacities and on the dates indicated.
Signature
Date
/s/ John K. Reinhart
March 10, 2020
John K. Reinhart
President, Chief Executive Officer and Director
/s/ Michael L. Hodges
March 10, 2020
Michael L. Hodges
Executive Vice President and Chief Financial Officer
/s/ Timothy J. Loos
March 10, 2020
Timothy J. Loos
Senior Vice President - Accounting and Finance
/s/ Randall M. Albert
March 10, 2020
Randall M. Albert
Chairman
/s/ Mark E. Burroughs, Jr.
March 10, 2020
Mark E. Burroughs, Jr.
Director
/s/ Eugene I. Davis
March 10, 2020
Eugene I. Davis
Director
/s/ Don Dimitrievich
March 10, 2020
Don Dimitrievich
Director
/s/ Richard D. Paterson
March 10, 2020
Richard D. Paterson
Director
/s/ D. Martin Phillips
March 10, 2020
D. Martin Phillips
Director
/s/ Douglas E. Swanson, Jr.
March 10, 2020
Douglas E. Swanson, Jr.
Director
/s/ Robert L. Zorich
March 10, 2020
Robert L. Zorich
Director
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Montage Resources Corporation
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Montage Resources Corporation (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2019 and 2018, the related consolidated statements of comprehensive income, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated March 10, 2020 expressed an unqualified opinion.
Change in accounting principle
As discussed in Note 2 to the consolidated financial statements, the Company has changed its method of accounting for leases as of January 1, 2019, due to the adoption of Accounting Standards Codification Topic 842, Leases.
Basis for opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ GRANT THORNTON LLP
We have served as the Company’s auditor since 2011.
Pittsburgh, Pennsylvania
March 10, 2020
MONTAGE RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share data)
The accompanying notes are an integral part of these Consolidated Financial Statements.
MONTAGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
(in thousands except per share data)
The accompanying notes are an integral part of these Consolidated Financial Statements.
MONTAGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2019, 2018, and 2017
(in thousands, except share and per share data)
The accompanying notes are an integral part of these Consolidated Financial Statements.
MONTAGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
The accompanying notes are an integral part of these Consolidated Financial Statements.
MONTAGE RESOURCES CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2019, 2018, and 2017
Note 1-Organization and Nature of Operations
Montage Resources Corporation (the “Company”), is an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin of the United States, which encompasses the Utica Shale, Indian Castle/Flat Creek Shales and Marcellus Shale prospective areas.
Note 2-Summary of Significant Accounting Policies
(a) Basis of Presentation
The accompanying Consolidated Financial Statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). In the opinion of management, the accompanying Consolidated Financial Statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of December 31, 2019 and 2018, and the results of its operations, comprehensive income (loss) and its cash flows for the years ended December 31, 2019, 2018, and 2017.
Preparation in accordance with U.S. GAAP requires the Company to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. The Company’s management believes the major estimates and assumptions impacting the Consolidated Financial Statements are the following:
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estimates of proved reserves of oil and natural gas, which affect the calculations of depreciation, depletion, amortization and accretion and impairment of capitalized costs of oil and natural gas properties;
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estimates of asset retirement obligations;
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estimates of the fair value of oil and natural gas properties the Company owns, particularly properties that the Company has not yet explored, or fully explored, by drilling and completing wells;
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impairment of undeveloped properties and other assets; and
•
depreciation and depletion of property and equipment.
Actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions.
(b) Cash and Cash Equivalents
Cash and cash equivalents are comprised of cash in banks and highly liquid instruments with original maturities of three months or less, primarily consisting of bank time deposits and investments in institutional money market funds. The carrying amounts approximate fair value due to the short-term nature of these items. Cash in bank accounts at times may exceed federally insured limits.
(c) Accounts Receivable
Accounts receivable are carried at estimated net realizable value. Trade credit is generally extended on a short-term basis, and therefore, accounts receivable do not bear interest, although a finance charge may be applied to such receivables that are past due. A valuation allowance is provided for those accounts for which collection is estimated as doubtful and uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the party. The Company had no significant accounts receivables determined to be uncollectable as of December 31, 2019 or December 31, 2018.
The Company accrues revenue due to timing differences between the delivery of natural gas, NGLs, and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s records and management’s estimates of the related commodity sales and transportation and compression fees, which are, in turn, based upon applicable product prices.
(d) Property and Equipment
Oil and Natural Gas Properties
The Company follows the successful efforts method of accounting for its oil and natural gas operations. Acquisition costs for oil and natural gas properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion, amortization and accretion expense (See “Depreciation, Depletion, Amortization and Accretion ” below).
Costs incurred to acquire producing and non-producing leaseholds are capitalized. All unproved leasehold acquisition costs are initially capitalized, including the cost of leasing agents, title work and due diligence. If the Company acquires leases in a prospective area, these costs are capitalized as unproved leasehold costs. If no leases are acquired by the Company with respect to the initial costs incurred or the Company discontinues leasing in a prospective area, the costs are charged to exploration expense. Unproved leasehold costs that are determined to have proved oil and gas reserves are transferred to proved leasehold costs.
Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s Consolidated Statements of Operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s Consolidated Balance Sheets. Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s Consolidated Statements of Operations. Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment on a group basis, no gain or loss is recognized in the Company’s Consolidated Statements of Operations unless the proceeds exceed the original cost of the property, in which case a gain is recognized in the amount of such excess. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.
A summary of property and equipment including oil and natural gas properties is as follows (in thousands):
Exploration expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property, not subject to depletion, but charged to expense if and when the well is determined not to have found proved oil and gas reserves.
Other Property and Equipment
Other property and equipment include land, buildings, leasehold improvements, vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition.
(e) Accounts Payable and Accrued Liabilities
A summary of accounts payable is as follows (in thousands):
A summary of accrued liabilities is as follows (in thousands):
(f) Revenue Recognition
Product Revenue
The Company’s revenues are primarily derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from the natural gas. Sales of natural gas, NGLs, and oil are recognized when the Company satisfies a performance obligation by transferring control of a product to a customer. Payment is generally received one month after the sale has occurred.
Natural Gas
Under the Company’s natural gas sales contracts, the Company delivers natural gas to the purchaser at an agreed upon delivery point. Natural gas is transported from the wellhead to delivery points specified under sales contracts. To deliver natural gas to these points, the Company uses third parties to gather, compress, process and transport the natural gas. The Company maintains control of the natural gas during gathering, compression, processing, and transportation. The Company’s sales contracts provide that it receives a specific index price adjusted for pricing differentials. The Company transfers control of the product at the delivery point and recognizes revenue based on the contract price. The costs to gather, compress, process and transport the natural gas are recorded as transportation, gathering and compression expense.
NGLs
The Company sells NGLs directly to the NGLs purchaser. For these NGLs, the sales contracts provide that the Company deliver the product to the purchaser at an agreed upon delivery point and that the Company receives a specific index price adjusted for pricing differentials. The Company transfers control of the product to the purchaser at the delivery point and recognizes revenue based on the contract price. The costs to further process and transport NGLs are recorded as transportation, gathering and compression expense.
Oil
Under the Company’s oil sales contracts, the Company generally sells oil to the purchaser from storage tanks at central stabilization facilities and well pads and collects a contractually agreed upon index price, net of pricing differentials and certain costs incurred by third parties. The Company transfers control of the product from the central stabilization facilities and well pads to the purchaser and recognizes revenue based on the contract price.
Marketing Revenue
Brokered natural gas and marketing revenues are derived from activities to purchase and sell third-party natural gas and to market excess firm transportation capacity to third parties. The Company retains control of the purchased natural gas and NGLs prior to delivery to the purchaser. The Company has concluded that it is the principal in these arrangements and therefore the Company recognizes revenue on a gross basis, with costs to purchase and transport natural gas presented as brokered natural gas and marketing expense. Contracts to sell third party natural gas are generally subject to similar terms as contracts to sell the Company’s produced natural gas and NGLs. The Company satisfies performance obligations to the purchaser by transferring control of the product at the delivery point and recognizes revenue based on the price received from the purchaser.
Disaggregation of Revenue
The following table illustrates the revenue disaggregated by type for the periods indicated:
Transaction Price Allocated to Remaining Performance Obligations
A significant number of the Company’s product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient allowed in the revenue accounting standard that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligations are part of a contract that has an original expected duration of one year or less.
For any product sales that have a contract term greater than one year, the Company has also utilized the practical expedient that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. Currently, any product sales that have a contractual term greater than one year have no long-term fixed considerations.
Contract Balances
Under the Company’s sales contracts, customers are invoiced once performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities. Accounts receivable attributable to the Company’s revenue contracts with customers was $63.7 million and $94.1 million at December 31, 2019 and December 31, 2018, respectively.
(g) Major Customers
The Company sells production volumes to various purchasers. For the years ended December 31, 2019, 2018, and 2017, there were two, one and two customers, respectively, that accounted for 10% or more of the total natural gas, NGLs and oil sales. The following table sets forth the Company’s major customers and associated percentage of revenue for the periods indicated:
Management believes that the loss of any one customer would not have a material adverse effect on the Company’s ability to sell natural gas, NGLs and oil production because it believes that there are potential alternative purchasers although it may be necessary to establish relationships with new purchasers. However, there can be no assurance that the Company can establish such relationships or that those relationships will result in an increased number of purchasers.
(h) Concentration of Credit Risk
The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31, 2019 and December 31, 2018 (in thousands):
Oil and natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in Ohio, Pennsylvania and West Virginia. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.
By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, the Company exposes itself to the credit risk of counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, it is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Additionally, the Company uses master netting agreements to minimize credit-risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. The fair value of the Company’s commodity unsettled derivative contracts was a net asset position of $27.1 million and $5.7 million at December 31, 2019 and 2018, respectively. Other than as provided by the revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under the Company’s contracts, nor are they required to provide credit support to the Company. As of December 31, 2019, the Company did not have past-due receivables from or payables to any of the counterparties.
(i) Depreciation, Depletion, Amortization and Accretion
Oil and Natural Gas Properties
Depreciation, depletion, amortization and accretion (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a field level basis using total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. DD&A expense relating to proved oil and natural gas properties for the years ended December 31, 2019, 2018, and 2017 totaled approximately $153.8 million, $133.2 million and $117.3 million, respectively, and is included in depreciation, depletion, amortization and accretion expense in the Consolidated Financial Statements.
Other Property and Equipment
Depreciation with respect to other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from 5 to 40 years. Depreciation for the years ended December 31, 2019, 2018, and 2017 totaled approximately $2.2 million, $1.8 million and $2.0 million, respectively. This amount is included in depreciation, depletion, amortization and accretion expense in the Consolidated Statements of Operations.
(j) Impairment of Long-Lived Assets
The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.
The review of the Company’s oil and gas properties is done by determining if the historical cost of proved and unproved properties less the applicable accumulated DD&A and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves and a risk-adjusted portion of probable reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon current contracts in place, adjusted for basis differentials and market-related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets. There were no impairments of proved properties for the years ended December 31, 2019, 2018, and 2017.
When an impairment charge is recognized it represents a significant Level 3 measurement in the fair value hierarchy. The primary input used is the Company’s forecasted discount net cash flows.
The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.
Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the properties. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. The Company recorded impairment charges of unproved oil and gas properties related to lease expirations of $45.8 million, $27.6 million, and $28.3 million for the years ended December 31, 2019, 2018, and 2017, respectively. These costs are included in exploration expense in the Consolidated Statements of Operations.
(k) Income Taxes
The Company accounts for income taxes, as required, under the liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
ASC Topic 740 “Income Taxes” provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company has not recorded a reserve for any uncertain tax positions to date.
(l) Fair Value of Financial Instruments
The Company has established a hierarchy to measure its financial instruments at fair value, which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:
Level 1 -Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.
Level 2 -Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market date for substantially the entire contractual term of the asset or liability. The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) current market and contractual prices for the underlying instruments and (iv) volatility factors, as well as other relevant economic measures.
Level 3 -Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.
Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.
(m) Derivative Financial Instruments
The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of the energy commodities it sells.
Derivatives are recorded at fair value and are included on the Consolidated Balance Sheets as current and noncurrent assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual expiration date. Derivatives with expiration dates within the next 12 months are classified as current. The Company netted the fair value of derivatives by counterparty in the accompanying Consolidated Balance Sheets where the right to offset exists. The Company’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the Consolidated Statements of Operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. Premiums for options are included in cash flows from operating activities.
The valuation of the Company’s derivative financial instruments represents a Level 2 measurement in the fair value hierarchy.
(n) Asset Retirement Obligation
The Company recognizes a legal liability for its asset retirement obligations (“ARO”) in accordance with Topic ASC 410, “Asset Retirement and Environmental Obligations,” associated with the retirement of a tangible long-lived asset, in the period in which it is incurred or becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The Company measures the fair value of its ARO using expected future cash outflows for abandonment discounted back to the date that the abandonment obligation was measured using an estimated credit adjusted rate.
Estimating the future ARO requires management to make estimates and judgments based on historical estimates regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.
The following table sets forth the changes in the Company’s ARO liability for the periods indicated (in thousands):
The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to ARO represent a significant nonrecurring Level 3 measurement.
(o) Off-Balance Sheet Arrangements
The Company does not have any off-balance sheet arrangements.
(p) Segment Reporting
The Company operates in one industry segment: the oil and natural gas exploration and production industry in the United States. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.
(q) Debt Issuance Costs
The expenditures related to issuing debt are capitalized and reported as a reduction of the Company’s debt balance in the accompanying Consolidated Balance Sheets. These costs are amortized over the expected life of the related instruments using the effective interest rate method. When debt is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed.
During the years ended December 31, 2019, 2018, and 2017, the Company amortized $4.1 million, $3.6 million and $3.4 million, respectively, of deferred financing costs and debt discount to interest expense using the effective interest method.
(r) Recent Accounting Pronouncements
Recently Adopted
In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” The new standard provides guidance to increase transparency and comparability among organizations and industries by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. Entities are required to recognize all leases in the statement of financial position as assets and liabilities regardless of the leases’ classification. These requirements are effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period with early adoption permitted. In July 2018, the FASB issued ASU 2018-11, “Leases: Targeted Improvements.” The update provided an optional transition method of adoption that permitted entities to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Under the optional transition method, comparative financial information and disclosures are not required. The update also provided transition practical expedients. The standard required disclosures of the nature, maturity and value of an entity's lease liabilities and elections made by the entity. In March 2019, the FASB issued ASU 2019-01, “Leases: Codification Improvements,” which, among other things, clarified interim disclosure requirements in the year of ASU 2016-02 adoption.
The Company adopted these standards effective January 1, 2019 using the optional transition method of adoption. The Company implemented a third-party-sponsored lease accounting information system to facilitate the accounting and financial reporting requirements and implemented processes and controls to review new contracts and modifications to existing contracts that contain lease components for appropriate accounting treatment. See Note 6 - Leases for the disclosures required by the standards.
Accounting Pronouncements Not Yet Adopted
In June 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses: Measurement of Credit Losses on Financial Instruments”, and subsequently, the FASB issued several related ASUs to clarify the application of the credit loss standard. Among other things, these amendments require the measurement of all expected credit losses for financial assets held at the reporting date based on historical experience, current conditions, and reasonable and supportable forecasts. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables and any other financial assets not excluded from its scope that have a contractual right to receive cash. The amendments are effective for smaller reporting companies for fiscal years and interim periods within the fiscal years beginning after December 15, 2020. Early adoption is permitted. The Company is assessing the impact, if any, this guidance may have on our consolidated results of operations, financial position and financial disclosures, but does not currently anticipate a material impact.
Note 3-Acquisition
Eclipse Resources-PA, LP Acquisition
On January 18, 2018, Eclipse Resources-PA, LP, a wholly owned subsidiary of the Company, completed its acquisition of certain oil and gas leases, one producing well and other oil and gas rights and interests covering approximately 44,500 net acres located in Tioga and Potter Counties, Pennsylvania from Travis Peak Resources, LLC for an aggregate adjusted purchase price of $90 million, which was paid entirely with approximately 2.5
million shares of the Company’s common stock (the “Flat Castle Acquisition”). The transaction was accounted for as an asset acquisition. Approximately $86 million of the purchase price was allocated to unproved oil and natural gas properties and approximately $4 million was allocated to proved oil and gas properties associated with the producing well acquired. In addition, the Company capitalized approximately $1 million of transaction costs related to the acquisition.
During the year ended December 31, 2018, the Company assigned its option to purchase all of the outstanding equity interests of Cardinal NE Holdings, LLC (“Cardinal”), a wholly owned subsidiary of Cardinal Midstream II, LLC, which owns midstream infrastructure with associated gathering rights on acreage in the Indian Castle and Flat Creek Shales, to a third party. The third party exercised its option to purchase all of the outstanding equity interests of Cardinal in July 2018.
Merger with Blue Ridge Mountain Resources
On February 28, 2019, the Company completed its previously announced business combination transaction with Blue Ridge Mountain Resources, Inc. (“BRMR”) pursuant to that certain Agreement and Plan of Merger, dated as of August 25, 2018 and amended as of January 7, 2019 (the “Merger Agreement”), by and among the Company, Everest Merger Sub Inc., a Delaware corporation and a wholly owned subsidiary of the Company (“Merger Sub”), and BRMR. Pursuant to the Merger Agreement, Merger Sub merged with and into BRMR with BRMR continuing as the surviving corporation and a wholly owned subsidiary of the Company (the “BRMR Merger”).
As a result of the BRMR Merger, each share of common stock, par value $0.01 per share, of BRMR issued and outstanding immediately prior to the effective time of the BRMR Merger (the “Effective Time”), excluding certain Excluded Shares (as such term is defined in the Merger Agreement), was converted into the right to receive from the Company 0.29506 of a validly issued, fully-paid, and nonassessable share of common stock, par value $0.01 per share, of the Company. The exchange ratio reflects an adjustment to account for the 15-to-1 reverse stock (See Note 12- Net Income (Loss) Per Share). Former stockholders of BRMR will receive cash for any fractional shares of the Company’s common stock to which they might otherwise be entitled as a result of the BRMR Merger. In addition, upon completion of the BRMR Merger, all shares of BRMR restricted stock and all BRMR restricted stock units and performance interest awards were converted into the right to receive shares of common stock of the Company or cash, in each case as specified in the Merger Agreement.
In connection with the BRMR Merger, the Company incurred approximately $25.5 million and $4.0 million of costs for the years ended December 31, 2019 and 2018, respectively, which are included in General and administrative expense on the Consolidated Statements of Operations and Comprehensive Income (Loss). Approximately $131.7 million of revenues and approximately $14.0 million of net income from continuing operations are attributed to the BRMR Merger are included in the Company’s Consolidated Statement of Operations and Comprehensive Income (Loss) for the period from March 1, 2019 to December 31, 2019. Approximately $7.2 million of revenues and approximately $1.3 million of net income from discontinued operations are attributed to the BRMR Merger are included in the Company’s Consolidated Statement of Operations and Comprehensive Income (Loss) for the period from March 1, 2019 to December 31, 2019.
The following table summarizes the purchase price allocation and the values of assets acquired and liabilities assumed (in thousands):
The fair value measurements of oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of proved oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighed average cost of capital rate. The fair value of unproved properties was determined using a market approach utilizing recent transactions of a similar nature in the same basin. These inputs required significant judgements and estimates by management at the time of the valuation and are the most sensitive to possible future changes.
The following unaudited pro forma financial information represents the combined results for the Company as though the BRMR Merger had been completed on January 1, 2018. The pro forma combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the BRMR Merger taken place on January 1, 2018; furthermore, the financial information is not intended to be a projection of future results.
Note 4-Sale of Oil and Natural Gas Property Interests
Asset Sales
During the year ended December 31, 2017, the Company received approximately $0.5 million from a completed asset sale with a third party totaling approximately 100 acres. No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties.
During the year ended December 31, 2017, the Company received approximately $0.8 million from a completed asset sale with a third party totaling approximately 150 acres. As a result of this sale, the Company recognized a gain of approximately $0.2 million.
During the year ended December 31, 2018, the Company received approximately $6.0 million from a completed asset sale of approximately 1,000 acres to a third party. As a result of this sale, the Company recognized a gain of approximately $1.5 million.
During the year ended December 31, 2018, the Company received approximately $3.8 million from a completed asset sale of approximately 400 acres to a third party. No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties.
During the year ended December 31, 2018, the Company received approximately $0.3 million from a completed asset sale of approximately 50 acres to a third party. As a result of this sale, the Company recognized a gain of approximately $0.3 million.
During the year ended December 31, 2018, the Company sold the $0.2 million of pipeline assets. As a result of this sale, the Company recognized a loss of less than approximately $0.1 million. These pipeline assets were classified as held for sale on the Consolidated Balance Sheets as of December 31, 2015.
Note 5-Assets Held for Sale and Discontinued Operations
Assets Held for Sale
As a result of the BRMR Merger, the Company acquired certain assets that met the criteria for assets held for sale at the acquisition date, comprised of the net assets of Magnum Hunter Production, Inc. (“MHP”), a wholly-owned subsidiary of BRMR. These assets are located primarily in Kentucky and Tennessee.
The following summarizes assets and liabilities held for sale at December 31, 2019:
Discontinued Operations
The Company determined that the planned divestiture of MHP met the assets held for sale criteria and the criteria for classification as discontinued operations as of December 31, 2019. The Company included the results of operations for MHP for the year ended December 31, 2019 in discontinued operations as follows:
The Company had maintained an accrued liability of $3.5 million related to litigation involving MHP and a third-party regarding certain royalty and overriding royalty deductions and related payments under several farm-out agreements. The litigation concluded in April 2019 and, as a result, the Company removed the accrued liability and recognized corresponding income from discontinued operations for the year ended December 31, 2019.
Total operating and investing cash flows of discontinued operations for the year ended December 31, 2019 were as follows:
Note 6-Leases
The Company leases drilling rigs, compressors, vehicles, office space, and other equipment under non-cancelable operating leases expiring through 2036. Certain lease agreements may include options to renew the lease, terminate the lease early, or purchase the underlying asset(s). The Company determines the lease term at the lease commencement date as the non-cancelable period of the lease, including the options to extend or terminate the lease when such an option is reasonably certain to be exercised.
As discussed in Note 2-Summary of Significant Accounting Policies, the Company adopted ASU 2016-02, ASU 2018-11 and ASU 2019-01 “Leases (Topic 842)” on January 1, 2019 using the optional transition method of adoption. The Company elected a package of practical expedients that together allows an entity to not reassess (i) whether a contract is or contains a lease, (ii) lease classification, and (iii) initial direct costs. In addition, the Company elected the following practical expedients for all asset classes: (i) to not reassess certain land easements, (ii) to not apply the recognition requirements under the standard to short-term leases, and (iii) to combine and account for lease and nonlease contract components as a lease, which requires the capitalization of fixed nonlease payments on January 1, 2019 or lease effective date and recognition of variable nonlease payments as variable lease expense.
On January 1, 2019, the Company recorded a total of $10.4 million in right-of-use assets and corresponding new lease liabilities on its Consolidated Balance Sheets representing the present value of its future operating lease payments. Adoption of the standards did not require an adjustment to the opening balance of retained earnings. The discount rate used to determine present value was based on the rate of interest that the Company estimated it would have to pay to borrow (on a collateralized-basis over a similar term) an amount equal to the lease payments in a similar economic environment as of January 1, 2019. The Company is required to reassess the discount rate for any new and modified lease contracts as of the lease effective date.
The right-of-use assets and lease liabilities recognized upon adoption of ASU 2016-02 were based on the lease classifications, lease commitment amounts, and terms recognized under the prior lease accounting guidance. Leases with an initial term of 12 months or less, taking into account extensions if reasonably certain to be exercised, are considered short-term leases and are not recorded on the Consolidated Balance Sheet.
The Company incurred $16.0 million in operating lease cost during the year ended December 31, 2019. The operating lease right-of-use assets were reported in other noncurrent assets and the current and noncurrent portions of the operating lease liabilities were reported in current liabilities and noncurrent liabilities, respectively, on the Consolidated Balance Sheets. As of December 31, 2019, the operating right-of-use assets were $37.0 million and operating lease liabilities were $37.2 million, of which $12.7 million was classified as current. As of December 31, 2019, the weighted average remaining lease term was 3.7 years and the weighted average discount rate was 5.4%.
Supplemental cash flow information related to the Company’s operating leases is included in the table below (in thousands):
The Company’s lease liabilities with enforceable contract terms that are greater than one year mature as follows (in thousands):
As discussed in Note 2-Summary of Significant Accounting Policies, the Company elected a transition method to recognize the effects of applying the new standard as a cumulative-effect adjustment to the opening balance of retained earnings. Per ASU 2016-02, the entity electing this transition method should provide the required disclosures under Topic 840 for all periods that continue to be in accordance with Topic 840. As such, the Company included the future minimum lease commitments table below as of December 31, 2018. Future minimum lease commitments under non-cancellable leases at December 31, 2018 were as follows:
Note 7-Derivative Instruments
Commodity derivatives
The Company is exposed to market risk from changes in energy commodity prices within its operations. The Company utilizes derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas and oil. The Company currently uses a mix of over-the-counter fixed price swaps, basis swaps and put options spreads and collars to manage its exposure to commodity price fluctuations. All of the Company’s derivative instruments are used for risk management purposes and none are held for trading or speculative purposes.
By using derivative instruments to hedge exposures to changes in commodity prices, the Company is exposed to the credit risk of its counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, it is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of counterparties is subject to periodic review. As of December 31, 2019, the Company’s derivative instruments were with Bank of Montreal, BP Energy Company, Capital One N.A., Citibank, Citizens Bank N.A., EDF Energy, J Aron, KeyBank, N.A., Morgan Stanley, Royal Bank of Canada, and Wells Fargo. The Company has not experienced any issues of non-performance by derivative counterparties. Below is a summary of the Company’s derivative instrument positions, as of December 31, 2019, for future production periods:
Natural Gas Derivatives:
Oil Derivatives:
NGL Derivatives:
Fair values and gains (losses)
The following table summarizes the fair value of the Company’s derivative instruments on a gross basis and on a net basis as presented in the Consolidated Balance Sheets (in thousands). None of the derivative instruments are designated as hedges for accounting purposes.
(a)
The Company has agreements in place that allow for the financial right to offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.
The following table presents the Company’s reported gains and losses on derivative instruments and where such values are recorded in the Consolidated Statements of Operations for the periods presented (in thousands):
Note 8-Fair Value Measurements
Fair Value Measurement on a Recurring Basis
The following table presents, by level within the fair value hierarchy, the Company’s assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
The fair value of the Company’s derivatives is based on third-party pricing models, which utilize inputs that are readily available in the public market, such as natural gas forward curves. These values are compared to the values given by counterparties for reasonableness. Since natural gas swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2.
Nonfinancial Assets and Liabilities
Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis
of fair value of the oil and natural gas property acquired include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. (See Note 3- Acquisition).
Additionally, fair value is used to determine the inception value of the Company’s AROs. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to the Company’s ARO represent a nonrecurring Level 3 measurement. (See Note 2- Summary of Significant Accounting Policies).
The Company reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement. (See Note 2- Summary of Significant Accounting Policies).
The estimated fair values of the Company’s financial instruments closely approximate the carrying amounts due, except for long-term debt. (See Note 9- Debt).
Note 9-Debt
8.875% Senior Unsecured Notes Due 2023
On July 6, 2015, the Company issued $550 million in aggregate principal amount of 8.875% senior unsecured notes due 2023 at an issue price of 97.903% of principal amount of the notes, plus accrued and unpaid interest, if any, to Deutsche Bank Securities Inc. and other initial purchasers. In this private offering, the senior unsecured notes were sold for cash to qualified institutional buyers in the United States pursuant to Rule 144A of the Securities Act and to persons outside of the United States in compliance with Rule S under the Securities Act. Upon closing, the Company received proceeds of approximately $525.5 million, after deducting original issue discount, the initial purchasers discounts and offering expenses, of which the Company used approximately $510.7 million to finance the redemption of all of its outstanding 12.0% Senior PIK notes. The Company used the remaining proceeds to fund its capital expenditure plan and for general corporate purposes.
The indenture governing the senior unsecured notes contains covenants that, among other things, limit the ability of the Company and its restricted subsidiaries to: (i) incur additional indebtedness, (ii) pay dividends on capital stock or redeem, repurchase or retire the Company’s capital stock or subordinated indebtedness, (iii) transfer or sell assets, (iv) make investments, (v) create certain liens, (vi) enter into agreements that restrict dividends or other payments to the Company from its restricted subsidiaries, (vii) consolidate, merge or transfer all or substantially all of the assets of the Company and its restricted subsidiaries, taken as a whole, (viii) engage in transactions with affiliates, and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications set forth in the indenture. In addition, if the senior unsecured notes achieve an investment grade rating from either Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services, and no default under the indenture has then occurred and is continuing, many of such covenants will be suspended. The indenture also contains events of default, which include, among others and subject in certain cases to grace and cure periods, nonpayment of principal or interest, failure by the Company to comply with its other obligations under the indenture, payment defaults and accelerations with respect to certain other indebtedness of the Company and its restricted subsidiaries, failure of any guarantee on the senior unsecured notes to be enforceable, and certain events of bankruptcy or insolvency. The Company was in compliance with all applicable covenants in the indenture at December 31, 2019.
Based on Level 2 market data inputs, the fair value of the senior unsecured notes at December 31, 2019 was approximately $471.1 million.
Revolving Credit Facility
During the first quarter of 2014, Eclipse Resources I, LP, a wholly owned subsidiary of the Company (“Eclipse I”) entered into a $500 million senior secured revolving bank credit facility (the “revolving credit facility”) that was scheduled to mature in 2018. Borrowings under the revolving credit facility are subject to borrowing base limitations based on the collateral value of the Company’s proved properties and commodity hedge positions and are subject to semiannual redeterminations (April and October).
The credit agreement governing the revolving credit facility (as amended and restated, the “Credit Agreement”) was amended on January 12, 2015. The primary change effected by such amendment was to add the Company as a party to the revolving credit facility and thereby subject the Company to the representations, warranties, covenants and events of default provisions thereof. Relative to the Eclipse I’s previous credit agreement, the Credit Agreement also (i) requires financial reporting regarding, and tests financial covenants with respect to, the Company rather than Eclipse I, (ii) increases the basket sizes under certain of the negative covenants, and (iii) includes certain other changes favorable to Eclipse I. Other terms of the Credit Agreement remain generally consistent with Eclipse I’s previous credit agreement.
On February 24, 2016, the Company amended its revolving credit facility to, among other things, adjust the quarterly minimum interest coverage ratio, which is the ratio of EBITDAX to Cash Interest Expense (as such terms are defined in the Credit Agreement), and to permit the sale of certain conventional properties. The amendment to the Credit Agreement also increased the Applicable Margin (as defined in the Credit Agreement) applicable to loans and letter of credit participation fees under the Credit Agreement by 0.5%.
On February 24, 2017, the Company entered into an additional amendment that increased the borrowing base from $125 million to $175 million, while extending the maturity of the revolving credit facility to February 2020. In addition, the amendment modified the minimum interest coverage ratio covenant to a net leverage covenant of Net Debt (as defined in the Credit Agreement) to EBITDAX. On August 1, 2017, the Company entered into an additional amendment to the Credit Agreement that increased the borrowing base from $175 million to $225 million.
On February 28, 2019, the Company amended and restated the Credit Agreement to increase its revolving credit facility from $500 million to $1 billion. Further, the amended and restated Credit Agreement, among other things, increased the borrowing base from $225 million to $375 million (subject to scheduled and interim redeterminations based on the Company’s oil and natural gas reserves and other adjustments described therein) and extended the maturity date thereof to February 2024 (subject to earlier maturity in certain circumstances specified therein). The amended and restated Credit Agreement also adjusted the ratio of Consolidated Total Funded Net Debt to EBITDAX to provide that the Company will not, as of the last day of any fiscal quarter (commencing with the fiscal quarter ending March 31, 2019), permit its ratio of Consolidated Total Funded Net Debt to EBITDAX for the four previous fiscal quarters to be greater than 4.00 to 1.00.
On May 6, 2019, the borrowing base under the Credit Agreement was redetermined, which increased the borrowing base from $375 million to $400 million.
On September 19, 2019, the Company entered into an additional amendment to the Credit Agreement to, among other things, confirm the redetermination of the borrowing base under the Credit Agreement, which increased the borrowing base from $400 million to $500 million.
On November 11, 2019, the Company entered into an additional amendment to the Credit Agreement to, among other things, (a) provide that the Company, may under certain circumstances, voluntarily repurchase, prepay or otherwise redeem the Company’s outstanding 8.875% senior unsecured notes due 2023 and any Permitted Refinancing Debt thereof (as such term is defined in the Credit Agreement), provided that the aggregate amount spent for such repurchase, prepayment or redemption since November 11, 2019 does not exceed $50 million; and (b) reduce the ratio of Consolidated Total Funded Net Debt to EBITDAX that the Company is required to maintain in order to make certain Restricted Payments (as such terms are defined in the Credit Agreement) from 3:1 to 2.75:1.
At December 31, 2019, the borrowing base under the revolving credit facility was $500 million and the Company had $130.0 million in outstanding borrowings thereunder. After giving effect to outstanding letters of credit issued by the Company totaling $29.2 million, the Company had available borrowing capacity under the revolving credit facility of $340.8 million.
The revolving credit facility is secured by mortgages on 85% of the value of the Company’s properties and guarantees from the Company’s operating subsidiaries. The revolving credit facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and leverage coverage ratios. Interest is payable at a variable rate based on LIBOR or the prime rate based on the Company’s election at the time of borrowing. The Company was in compliance with all applicable covenants under the revolving credit facility as of December 31, 2019. Commitment fees on the unused portion of the revolving credit facility are due quarterly at 0.375%-0.500% of the unused facility based on utilization.
Note 10-Benefit Plans
Defined Contribution Plan
The Company currently maintains a retirement plan intended to provide benefits under section 401(k) of the Internal Revenue Code, as amended (“the Code”), under which employees are allowed to contribute portions of their compensation to a tax-qualified retirement account. Under the 401(k) plan, the Company provides matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the plan. The Company recorded compensation expense of $1.0 million, $0.9 million and $0.7 million related to matching contributions, classified under general and administrative, for the years ended December 31, 2019, 2018, and 2017, respectively.
Note 11-Stock-Based Compensation
At the Company’s 2019 Annual Meeting of Stockholders held on June 14, 2019, the Company’s stockholders approved the Company’s 2019 Long-Term Incentive Plan (the “2019 Plan”), which was previously approved by the Company’s Board of Directors. The 2019 Plan replaces the Company’s 2014 Long-Term Incentive Plan, as amended (the “Prior Plan”). Upon stockholder approval, (i) the 2019 Plan became effective, and (ii) the Prior Plan terminated, and no additional awards will be granted under the Prior Plan; provided that awards outstanding under the Prior Plan as of the date the 2019 Plan became effective will remain in full force and effect under the Prior Plan according to their respective terms.
The Company is authorized to grant up to 2,650,000 shares of common stock under the 2019 Plan. The 2019 Plan allows stock-based compensation awards to be granted in a variety of forms, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent rights, performance-based awards and other types of awards. The terms and conditions of the awards granted are established by the Compensation Committee of the Company’s Board of Directors. A total of 1,745,810 shares were available for future grants under the Plan as of December 31, 2019.
Stock-based compensation expense was as follows for the years ended December 31, 2019, 2018, and 2017 (in thousands):
Restricted Stock Units
Restricted stock unit awards vest subject to the satisfaction of service requirements. The Company recognizes expense related to restricted stock unit awards on a straight-line basis over the requisite service period, which is three years. The grant date fair values of these awards are determined based on the closing price of the Company’s common stock on the date of the grant. As of December 31, 2019, there was $2.4 million of total unrecognized compensation cost related to restricted stock units. The weighted average period for the units to vest is approximately one year.
A summary of employee restricted stock unit awards activity during the year ended December 31, 2019 is as follows:
Performance Units
Performance unit awards vest subject to the satisfaction of a three-year service requirement and based on Total Shareholder Return (“TSR”), as compared to an industry peer group over that same period. The performance unit awards are measured at the grant date at fair value using a Monte Carlo valuation method. As of December 31, 2019, there was $1.7 million of total unrecognized compensation cost related to performance units. The weighted average period for the units to vest is approximately two years.
A summary of performance stock unit awards activity during the year ended December 31, 2019 is as follows:
The determination of the fair value of the performance unit awards noted above uses significant Level 3 assumptions in the fair value hierarchy including an estimate of the timing of forfeitures, the risk-free rate and a volatility estimate tied to the Company’s public peer group. The following table presents the assumptions used to determine the fair value for performance stock units granted during the years ended December 31, 2019, 2018, and 2017:
The fair value of the performance stock units vested during the years ended December 31, 2019 and December 31, 2017 was approximately $3.7 million and $0.8 million, respectively.
Restricted Stock Issued to Directors
On May 18, 2016, the Company issued an aggregate of 9,963 restricted shares of common stock to its three non-employee members of its Board of Directors that were not affiliated with the Company’s then controlling stockholder, which became fully vested on May 18, 2017.
On May 17, 2017, the Company issued an aggregate of 10,212 restricted shares of common stock to its three non-employee members of its Board of Directors that were not affiliated with the Company’s then controlling stockholder, which became fully vested on May 17, 2018.
On May 16, 2018, the Company issued an aggregate of 15,476 restricted shares of common stock to its three non-employee members of its Board of Directors that were not affiliated with the Company’s then controlling stockholder, which became fully vested on May 16, 2019.
Effective February 28, 2019, the Company issued an aggregate of 70,409 restricted shares of common stock to two of its officers in connection with retention bonus arrangements entered into between the Company and each of these officers. Twenty-five percent of the restricted shares vested on August 28, 2019, and the remaining 75% of the restricted shares vest in substantially equal installments on February 28, 2020, August 28, 2020 and February 28, 2021.
Pursuant to the Company’s Non-Employee Director Compensation Policy, on June 18, 2019, the Company awarded an aggregate of 53,328 restricted shares of common stock to eight of the non-employee members of its Board of Directors, which shares are scheduled to fully vest on June 18, 2020. The other non-employee member of the Company’s Board of Directors declined to receive any compensation for his service on the Company’s Board of Directors for 2019.
Pursuant to the Company’s Non-Employee Director Compensation Policy, on August 2, 2019 and October 8, 2019, the Company issued an aggregate of 26,935 and 22,661 unrestricted shares of common stock, respectively, which vested immediately to four of the non-employee members of its Board of Directors.
As of December 31, 2019, there was $0.9 million of total unrecognized compensation cost related to restricted stock units issued to Directors.
Note 12-Net Income (Loss) Per Share
Net Income (Loss) Per Share
Basic earnings (loss) per share (“EPS”) is computed by dividing net income (loss) by the weighted-average number of shares of common stock outstanding during the period. Diluted EPS takes into account the dilutive effect of potential common stock that could be issued by the Company in conjunction with any stock awards that have been granted to directors and employees. In accordance with FASB ASC Topic 260, awards of non-vested shares shall be considered to be outstanding as of the grant date for purposes of computing diluted EPS even though their exercise is contingent upon vesting. During periods in which the Company incurs a net loss, diluted weighted-average shares outstanding are equal to basic weighted-average shares outstanding because the effect of all equity awards is antidilutive.
Reverse Stock Split
Effective immediately prior to the Effective Time on February 28, 2019 (See Note 3- Acquisition), the Company effected a 15-to-1 reverse stock split of its common stock. Holders of shares of the Company’s common stock immediately prior to the Effective Time received cash for any fractional shares of the Company’s common stock to which they might otherwise have been entitled as a result of the reverse stock split. The reverse stock split lowered the aggregate par value of the common stock reflected in the Consolidated Statements of Stockholders’ Equity to reflect the reduced shares with the offset to additional paid-in-capital. The table below retroactively reflects, in accordance with ASC 505 “Equity”, the stock split that occurred on February 28, 2019 for the years ended December 31, 2018 and 2017, respectively. The following is a calculation of the basic and diluted weighted-average number of shares of common stock and EPS for the years ended December 31, 2019, 2018, and 2017:
Note 13-Related Party Transactions
During the years ended December 31, 2018 and 2017, the Company incurred approximately $0.6 million, respectively, related to flight charter services provided by BWH Air, LLC and BWH Air II, LLC, which were owned by the Company’s former Chairman, President and Chief Executive Officer. The Company incurred less than $0.1 million for these services for the year ended December 31, 2019. The fees were paid in accordance with a standard service contract that did not obligate the Company to any minimum terms. The Company no longer utilizes any flight charter services under this arrangement.
Travis Peak Resources, LLC, the seller from whom the Company acquired assets in the Flat Castle Acquisition, is an affiliate of EnCap Investments L.P. (“EnCap”). EnCap has representatives on the Company’s Board of Directors, and affiliates of EnCap collectively beneficially own approximately 40% of the outstanding shares of the Company’s common stock. (See Note 3- Acquisition).
Note 14-Commitments and Contingencies
(a) Legal Matters
From time to time, the Company may be a party to legal proceedings arising in the ordinary course of business. Management does not believe that a material loss is probable as a result of such proceedings.
During the year ended December 31, 2019, the Company removed an accrued liability related to certain litigation involving MHP (See Note 5- Assets Held for Sale and Discontinued Operations).
(b) Environmental Matters
The Company is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of the Company could be adversely affected.
(c) Other Commitments (in thousands)
(i)
Firm transportation - The Company has entered into firm transportation agreements with various pipelines in order to facilitate the delivery of production to market. These contracts commit the Company to transport minimum daily natural gas volumes at a negotiated rate, or pay for any deficiencies at a specified reservation fee rate. The amounts in this table represent the minimum daily volumes at the reservation fee rate. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its Consolidated Financial Statements the Company’s proportionate share of costs based on its working interest.
(ii)
Gas processing, gathering, and compression services - Contractual commitments for gas processing, gathering and compression service agreements represent minimum commitments under long-term gas processing and gathering agreements as well as various gas compression agreements. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its Consolidated Financial Statements its proportionate share of costs based on the Company’s working interest.
See Note 6- Leases for a summary of undiscounted future cash flows owed by the Company as lessee to lessors pursuant to contractual agreements in effect as of December 31, 2019.
Note 15-Income Tax
The components of the Company’s income tax expense from continuing operations are as follows (in thousands):
The Company’s income tax expense from continuing operations differs from the amount derived by applying the statutory federal rate to pretax loss principally due the effect of the following items (in thousands):
Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of the Company’s deferred taxes are detailed in the table below (in thousands):
Deferred tax assets and liabilities are recognized for the estimated future tax effects of temporary differences between the tax basis of an asset or liability and its reported amount in the Consolidated Financial Statements. The measurement of deferred tax assets and liabilities is based on enacted tax laws and rates currently in effect in each of the jurisdictions in which we have operations.
In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income of the appropriate character during the periods in which those deferred income tax assets would be deductible. The Company considers the scheduled reversal of deferred income tax liabilities and projected future taxable income for this determination. Due to the history of losses in recent years, management believes that it is more likely than not that the Company will not be able to realize our net deferred tax assets, and therefore a valuation allowance on the entire net deferred tax asset is maintained.
The Company has U.S. federal tax loss carryforwards (“NOL”) of approximately $1.4 billion as of December 31, 2019 of which $386 million could be permanently lost. The NOL carryforwards will begin to expire in 2034. In connection with the BRMR Merger (See Note 3- Acquisition), the Company experienced an ownership change as described in IRC Section 382. As a result, the Company’s net operating losses as of December 31, 2019 as well as certain tax deductions are subject to an annual limitation imposed by Section 382 limitation. If a subsequent ownership change were to occur as a result of future transactions in the Company’s stock, the Company’s use of remaining U.S. tax attributes may be further limited.
The tax years ended December 31, 2016 through 2019 will remain open to examination under the applicable statute of limitations in the U.S. and other jurisdictions in which the Company and its subsidiaries file income tax returns. However, the statute of limitations for examination of NOLs and other similar attribute carryforwards does not commence until the year the attribute is utilized. In some instances, state statutes of limitations are longer than those under U.S. federal tax law.
As of December 31, 2019, 2018, and 2017 the Company has not recorded a reserve for any uncertain tax positions. No federal income tax payments are expected in the upcoming four quarterly reporting periods. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense. In the Company’s major tax jurisdictions, the earliest year open to examination is 2007.
Note 16-Subsidiary Guarantors
Each subsidiary of the Company that guarantees the Company’s revolving credit facility is required to fully and unconditionally, joint and severally, guarantee the Company’s 8.875% senior unsecured notes. Each such subsidiary of the Company in existence immediately prior to the BRMR Merger guaranteed the Company’s 8.875% senior unsecured notes. As a result of the BRMR Merger, and within the timeframe required by the indenture governing the Company’s 8.875% senior unsecured notes, the Company caused BRMR and each of its subsidiaries that guaranteed the Company’s revolving credit facility to guarantee the Company’s 8.875% senior unsecured notes (See Note 9- Debt ). Montage Resources Corporation, standing alone, has no independent operations or (other than its equity interests in its subsidiaries) material assets. The Company’s wholly owned subsidiary guarantors are not restricted from transferring funds to Montage Resources Corporation or other wholly owned subsidiary guarantors. The Company’s wholly owned subsidiaries do not have any restricted net assets.
A subsidiary guarantor may be released from its obligations under the guarantee:
•
in the event of a sale or other disposition of all or substantially all of the assets of the subsidiary guarantor or a sale or other disposition of all the capital stock of the subsidiary guarantor, to any corporation or other person by way of merger, consolidation, or otherwise; or
•
if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the terms of the indenture governing the senior unsecured notes.
Note 17-Subsequent Events
Management has evaluated subsequent events and believes that there are no events that would have a material impact on the aforementioned financial statements and related disclosures in the accompanying notes to the Consolidated Financial Statements.
Note 18-Quarterly Financial Information (unaudited)
Summarized quarterly financial data for the years ended December 31, 2019 and 2018 are presented in the following table. Quarterly financial data for the year ended December 31, 2018 retroactively reflects the 15-to-1 reverse stock split at the close the BRMR Merger on February 28, 2019. In the following table, the sum of basic and diluted “Income (loss) per common share” for the four quarters may differ from the annual amounts due to the required method of computing weighted average number of shares in the respective periods. Additionally, due to the effect of rounding, the sum of the individual quarterly loss per share amounts may not equal the calculated year loss per share amount (in thousands, except per share data).
Note 19-Supplemental Oil and Natural Gas Information (unaudited)
(a) Capitalized Costs
A summary of the Company’s capitalized costs are contained in the table below (in thousands):
(b) Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities
A summary of the Company’s cost incurred in oil and natural gas property acquisition and development activities is set forth below (in thousands):
(c) Reserve Quantity Information
The following information represents estimates of the Company’s proved reserves as of December 31, 2019 and December 31, 2018, which have been prepared and presented under SEC rules. These rules require companies to prepare their reserve estimates using specified reserve definitions and pricing based on a 12-month unweighted average of the first-day-of-the-month pricing. The pricing that was used for estimates of the Company’s reserves as of December 31, 2019, 2018, and 2017 was based on an unweighted average 12-month average West Texas Intermediate posted price per Bbl for oil and NGLs and a Henry Hub spot natural gas price per MMBtu for natural gas.
Subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This requirement may limit the Company’s potential to record additional proved undeveloped reserves as it pursues its drilling program, particularly as it develops its significant acreage primarily in the Appalachian Basin of Ohio, Pennsylvania and West Virginia. Moreover, the Company may be required to write down its proved undeveloped reserves if it does not drill on those reserves within the required five-year timeframe. The Company does not have any proved undeveloped reserves which have remained undeveloped for five years or more.
The Company’s proved oil and natural gas reserves are all located in the United States, primarily within the States of Ohio, Pennsylvania and West Virginia. All of the estimates of the proved reserves at December 31, 2019 and 2018 and December 31, 2017, were prepared by SIS and NSAI, our independent petroleum engineers, respectively. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB.
Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates.
Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.
The following table provides a roll-forward of the total proved reserves for the year ended December 31, 2019, 2018, and 2017 as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year:
2017 Changes in Reserves
•
Extensions of 405.1 Bcfe primarily from 361.0 Bcfe of development of the Company’s operated Utica asset. The Company also added 0.3 Bcfe from one non-operated Utica well through development. In addition, the Company proved 43.8 Bcfe from 3 Ohio Marcellus wells due to development in the Ohio Marcellus asset.
•
Positive revisions of 695.6 Bcfe as a result of a positive revision of 607.2 Bcfe due to improvements in SEC pricing, a positive revision of 61.4 Bcfe due to changes in pricing differentials, and a positive revision of 69.6 Bcfe primarily driven by proved developed producing wells in aggregate outperforming the previous estimate. This was offset by a negative revision of 42.6 Bcfe due a decision to not develop certain proved, undeveloped reserves within five years.
2018 Changes in Reserves
•
Extensions of 558.1 Bcfe from the development of 148.3 Bcfe of unproved wells to proved developed, 398.2 Bcfe from the development of the Company’s operated Utica asset and 11.6 Bcfe from the Company’s operated Marcellus asset.
•
16.3 Bcfe related to acquiring proved developed leasehold acreage in the Indian Castle/Flat Creek and Utica Shales.
•
0.2 Bcfe related to divesting a non-operated proved developed well in the Utica Shale.
•
Negative revisions of 42.8 Bcfe as a result of a positive revision of 15.0 Bcfe due to improvements in SEC pricing, a positive revision of 6.8 Bcfe due to changes in pricing differentials and a positive revision of 67.5 Bcfe primarily driven by proved developed producing wells outperforming the previous estimate. This was offset by a negative revision of 98.0 Bcfe due to changes in well spacing and 34.1 Bcfe due to changes in the five year development plan.
2019 Changes in Reserves
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Extensions of 599.2 Bcfe from the development of 100.5 Bcfe of unproved wells to proved developed, of which 70.2 Bcfe is from the development of the Company’s operated Marcellus asset, 23.3 Bcfe is from the Company’s operated Utica asset and 7.0 Bcfe was added from participation in non-operated wells. Extensions of 498.7 Bcfe from the development of unproved wells to proved undeveloped, of which 269.4 Bcfe is from the Company’s operated Utica asset and 229.3 Bcfe is from the Company’s operated Marcellus asset.
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525.5 Bcfe related to acquiring proved assets from the merger with BRMR.
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Revisions to previous estimates are comprised of 59.6 Bcfe of negative revisions primarily due to a negative adjustment of 277.3 due to downward SEC pricing and differentials and 44.2 Bcfe due adjustments in the drilling schedule. The negative revisions have been offset by a positive revision of 261.9 Bcfe due to well performance, capital allocation, and lease operating expense.
(d) Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs as of December 31, 2019 and 2018 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows at December 31, 2019, 2018, and 2017 (in thousands):
It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the Company’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.
(e) Changes in the Standardized Measure of Discounted Future Net Cash Flows
A summary of the changes in the standardized measure of discounted future net cash flows are contained in the table below (in thousands):